2020 PERC Annual Report by Philippine Integrated Advertising Agency, Inc.

OUR MISSION

OUR VISION

• Meet people’s energy needs thru strategic initiatives;

To grow into one of the most profitable publicly-listed energy companies in the Philippines through judicious investments in conventional and renewable energy exploration, development, and generation.

• Provide optimum value to our shareholders; • Develop and retain highly motivated employees; and • Uplift the communities where we operate.

ABOUT THE COVER PERC’s 2020 Annual Report cover depicts the Company’s main strategies in surviving COVID-19 disruptions – leveraging on technology and capitalizing on human resource. These two (2) approaches helped PERC boost its overall company performance, while safeguarding the health and jobs of its employees and the well-being of its host communities.

TABLE OF CONTENTS Financial & Operational Highlights

Message to our Shareholders

II.

Operations Review

III.

CSR in Times of Disruptions

IV.

Board of Directors

Senior Management & Corporate Directory

VI.

Statement of Management’s Responsibility for Financial Statements

VII.

Photo credits to: The paper used in this CSR Report is certified by Programme for the Endorsement of Forest Certification (PEFC) signifying that the forest-based materials used in the paper came from sustainably-managed forests. Our printer, Primex Printers, Inc., also utilizes Kodak Sonora process-free plates, soy-based ink, and a Heidelberg carbon neutral offset press resulting in lesser chemical wastes and air contaminants during the printing process. These show how PERC gives high importance to environmental preservation and to its sustainability journey.

Adriann Vasquez (PERC) Engr. Lew delos Santos (PWEI) Engr. Ian Mendivil (MGI) Engr. John Paul de Luna (PSC) PERC Group CSR Team –

PWEI’s wind turbine towering over the mountains of Nabas, Aklan

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

II.

Helen Y. Dee Chairman of the Board

OPERATIONS

MESSAGE TO OUR SHAREHOLDERS It has been an extremely challenging year which required bold, innovative planning and calculated moves by your Company to navigate the uncharted market environment brought about by the COVID-19 pandemic. This approach boosted your Company’s performance in 2020, so that despite widespread economic disruptions, your Company’s consolidated net income increased by 21% from P534 Million in 2019 to P646 Million in 2020. Net income attributable to parent company also increased by 9% over the same period from P293 Million to P319 Million. Although our Gabon petroleum operations yielded lower revenues due to depressed global crude oil price, our renewable energy ventures posted higher income mainly due to the full year operation of the 20MWDC Tarlac-2 solar power plant and higher than forecast solar power generation brought by prolonged summer weather in 2020.

Our four (4) Gabon oil fields exported 6.02 million barrels of oil (MMBO) from 11 liftings. Prior to the pandemic, the Consortium had completed a three-well drilling program and two-well workovers, which increased the Gabon production from ~11,000 barrels of oil per day (BOPD) in October 2019, to ~22,000 BOPD in February 2020. The crash in crude prices was somewhat compensated by the higher production volumes. Unfortunately, in March 2020, the Gabonese government imposed an OPECmandated curtailment of production due to global supply and demand imbalance. Our crude production was thus choked down to ~14,000 BOPD.

Our renewable energy power operations remained robust during this pandemic. Although we had to shift to remote working arrangements for some of our personnel, our operations team continued to work on site throughout varying quarantine restrictions. Our 20MW Maibarara-1 and 12MW Maibarara-2 geothermal power facilities generated an aggregate 259.07 GWh of electricity in 2020. Equally significant, despite mobility restrictions and global supply chain disruptions, our Maibarara operations team completed the scheduled minor preventive maintenance of our two geothermal units, the related maintenance of our substation and transmission line, and the critical wellhead valve replacement of production well MB-12D. In Aklan, our 36MW Nabas-1 wind power facility generated power that is lower than forecast at 80.46 GWh, due to extended low-wind summer weather last year. However, it still posted significant revenues because of the FIT rate adjustment that took effect last year.

Workers on Gabon oilfield platform

In November 2020, the Consortium completed a 1,000 sq.km 3D seismic survey over the Etame Marin block in preparation for full field development. It is now studying the most feasible development plan to extract the remaining recoverable reserves estimated at 50 MMBO.

70MWDC Tarlac Solar Power Facility

Solar 1

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PWEI’s road side planting activities contribute to the re-greening of the area

For our Philippine petroleum projects, we are pleased to report that after five (5) years, the Department of Energy (DOE) lifted the Force Majeure hold on our Northwest Palawan Service Contract (SC 75). This means the Consortium can resume its work program commitments barring any other security and regulatory constraints.

The low electricity generation of our Nabas wind farm was offset however by the high output achieved by our 50MWDC Tarlac-1 solar power facility. Tarlac-1 performed above forecast for seven (7) months producing a total of 71.93 GWh of electricity. In addition, our second operating unit in Tarlac, the 20MWDC Tarlac-2, exported a total of 29.75 GWh.

Our West Linapacan (SC 14C2) block in Northwest Palawan continues to undergo in-house Geological and Geophysical (G&G) studies. The Consortium is also negotiating with a potential farmee, subject to approval of the DOE. In our other Northwest Palawan brownfield block, the Octon-Malajon (SC 6A) service contract, operator Philodrill is evaluating re-development prospects and drilling opportunities. It is likewise assessing a potential farm-in opportunity for the southern portion of the block.

We are pleased to report another milestone in our renewable energy venture – the completion of our first commercial and industrial (C&I) rooftop solar project. Our subsidiary, PetroGreen Energy Corporation (PGEC) completed a 140.8-kWp solar rooftop system for the Enrique T. Yuchengco (ETY) Bldg. in Binondo, Manila. Completed in less than 15 weeks, the rooftop project is under a 15-year Rent-to-Own Agreement with ETY building manager, Landev Corporation. PETROENERGY RESOURCES CORPORATION

LOOKING AHEAD III.

While volatile global oil conditions in 2020 brought extreme challenge to our oil exploration and development activities, these same conditions validated renewable energy (RE) ventures as important and long term solution to the country’s energy needs. Not only is RE less susceptible to supply chain disruptions, but it reduces atmospheric pollution and promotes a healthy environment, which is going to be one of the top priorities across societies, moving forward. Thus, we continue to advance towards this direction, as we look to aggressively pursue our various projects already in the pipeline in Luzon and the Visayas. For the medium term, we are in collaboration with a foreign partner to further expand our footprint in the offshore wind power generation in the country.

OPERATIONS REVIEW

SURVIVING DISRUPTIONS The COVID-19 pandemic underscored a very insightful observation - innovation is key to surviving disruptions. For our Company, we immediately put to action our Crisis Management Team (CMT) to ensure that we implement the most efficient work arrangements for our employees without compromising health and operations. We focused our responses to two (2) aspects – leveraging on technology and capitalizing on our human resource. PERC’s workforce is a pool of highly-skilled and welltrained individuals who can easily adapt to fastevolving technologies and work environment. These characteristics and our lean organizational structure became an advantage when we needed to deploy work-from-home (WFH) tools and implement new work schedules for our back room activities and support processes. We also strengthened our IT capabilities and safeguards by utilizing readily available tools for online collaboration and remote monitoring of our sites.

Brgy. Pawa falls in Nabas, Aklan is among the tributaries included in PWEI’s environmental rehabilitation projects

Over a year into this pandemic, we believe that people and industries have learned to adapt and to function in these trying circumstances. It is thus timely for PERC to re-calibrate and go full steam ahead with our new projects and ventures. This is only possible through continuous innovation, your abiding trust in us, and the teamwork and dedication of our staff and management.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

FOREIGN OIL OPERATIONS Etame Marin, Offshore Gabon

6.57

MMBO

Liftings

In November 2020, the consortium completed a 1,000 sq.km 3D seismic survey over the Etame Marin block using the Polarcus Adira seismic vessel. The survey aimed to explore other drilling targets within the existing fields as well as other near-field structures which can be programmed in the drilling campaigns to start in late2021 to 2022. PERC holds 2.525% participating interest in the Etame Marin block. The other Consortium members and their respective participating interests are as follows: Addax Petroleum Etame, Inc. (33.90%), and Operator VAALCO Gabon S.A. (63.575%).

~22,000 BOPD

Total crude production in 2020 reached 6.57 million barrels of oil (MMBO) from four (4) oil fields (Etame, Avouma, Ebouri and North Tchibala). The Consortium managed 11 liftings, resulting in a net crude export of 6.02 MMBO with crude oil market prices ranging from US$ 17 - 66 per barrel. Upon completion of the three-well drilling and twowell workover program in February 2020, overall crude production rose from just ~11,000 barrels of oil per day (BOPD) in October 2019 to ~22,000 BOPD – last experienced in mid-2009 after the Ebouri Field was put on-line.

Since the Gabon oilfield went on-line in 2002, approximately 119 MMBO have been produced todate. Given the extended Exploration and Production Sharing Contract (EPSC) period, the Consortium is currently firming up the most feasible Integrated Field Development Plan (IFDP) to extract the remaining recoverable oil volumes until at least 2028. This IFDP may include: 1) production from sour oil reserves, 2) outfield drilling opportunities, and 3) facility maintenance strategies.

SERVICE CONTRACT 6A (Octon-Malajon, Northwest Palawan)

SERVICE CONTRACT 14C2 (West Linapacan, Northwest Palawan)

SERVICE CONTRACT 75 (Offshore Northwest Palawan)

Service Contract 6A (Octon-Malajon, Northwest Palawan) Service Contract 14C2 (West Linapacan, Northwest Palawan) Octon-Malajon (SC 6A) and West Linapacan (SC 14C2) are

two (2) brownfield blocks in offshore Northwest Palawan with potential for re-development and production. PERC and fellow Philippine consortium partners, led by Philodrill Corporation (Philodrill), are evaluating ways on how to best re-develop these mature fields. In 2020, SC 6A Operator Philodrill engaged Dubai-based consultants LMKR to conduct Quantitative Interpretation (QI) works to determine possible drilling opportunities in the northern portion of the block (Malajon field); the results of which were provided to the consortium in January 2021.

2 3

In July 2020, the Gabonese government imposed a production curtailment on the Etame Marin block to comply with OPEC-mandated supply cuts. This was due to global supply-demand imbalance brought about by COVID-19-related business and operational restrictions starting March 2020. Overall crude production was reduced to ~14,000 - 16,000 BOPD up to March 2021. Floating Storage & Offloading Vessel - Queensway

in exchange for a majority share and Operatorship of SC 14C2. This farm-in is subject to the approval of the Department of Energy (DOE). While the consortium awaited the farmee’s completion of the farm-in documentation, Philodrill continued to do in-house Geological & Geophysical (G&G) reviews at the West Linapacan area at the interim. For compliance, a “Transition Work Program and Budget, covering November 2020 to March 2021 was submitted to the DOE in November 2020 and was approved. PERC holds a 4.13% participating interest in SC14C2. Service Contract 75 (Offshore Northwest Palawan) In 2020, the Company saw its remaining exploration block resume activities after five (5) years.

PERC holds a 16.670% participating interest in SC 6A.

Service Contract 75 (Northwest Palawan) was reactivated on October 14, 2020 when the DOE issued a formal notice to the SC 75 consortium, lifting the Force Majeure imposed since September 09, 2015. Through this letter, the consortium was notified to resume its Work Program commitments under SC 75.

In SC 14C2 (West Linapacan field), Operator Philodrill and the SC 14C2 Consortium negotiated with a potential farmee for the drilling of these potential drilling targets,

PXP Energy Corporation is the operator of SC 75 with 50.00% participating interest, PNOC-EC with 35.00%, and PERC with 15.00%.

In parallel, Philodrill is also reviewing a third-party technical evaluation on the southern portion of the block for a potential farm-in opportunity. SC 6A is set to run until 2024.

Ebouri platform

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

In February 2021, VAALCO completed the full acquisition of 30.00% of previous partner Sasol Gabon S.A.’s participating interests through a Sale & Purchase Agreement. This divestment increased VAALCO’s participating interests to 63.575%.

The consortium is looking at two (2) options for the crude handling at the Etame Marin block; 1) purchase the Petroleo Nautipa FPSO from owner BWO before September 2022, or 2) lease a new Floating Storage and Offtake (FSO) vessel from another contractor before September 2022.

PHILIPPINE UPSTREAM OIL PROJECTS

PETROENERGY RESOURCES CORPORATION

MGPP steamfield surrounded by lush green vegetation

RENE WABLE ENERGY

20 MW MAIBARARA-1 GEOTHERMAL POWER FACILITY (Maibarara-1)

165.10 GWh Electricity Exported

98.41%

Capacity Factor

99.84%

Availability Factor

12 MW MAIBARARA-2 GEOTHERMAL POWER FACILITY (Maibarara-2)

93.97 GWh

Electricity Exported

96.51%

Capacity Factor

97.04%

The Nabas Wind Farm in a picturesque scene during sunset, overlooking the famous island of Boracay

Despite the COVID-19 pandemic in early-2020, PERC continued to operate its renewable energy (RE) power plants, with steady revenues from the 32MW Maibarara Geothermal Power Facility (20MW Maibarara-1 and 12MW Maibarara-2), the 36MW Nabas-1 Wind Power Facility (Nabas-1), and the 70MWDC Tarlac Solar Power Facility (50MWDC Tarlac-1 and 20MWDC Tarlac-2).

With the pandemic’s adverse impact on the economy and the country, PERC explored other opportunities in the Commercial & Industrial (C&I) rooftop solar business. This resulted in the construction of a new 140-kWp rooftop solar facility for a client in Binondo, Manila in early-2021.

Availability Factor

20 MW MAIBARARA-1 GEOTHERMAL POWER FACILITY

Water quality monitoring in MGPP

(Maibarara-1) PERC’s first RE investment, Maibarara-1, started commercial operations on February 08, 2014. In 2020, it exported 165.10 GWh of electricity at an average capacity factor of 98.41% and availability factor of 99.84%.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

MGI contractors follow strict health protocols during the preventive maintenance

20 MW MAIBARARA-1 GEOTHERMAL POWER FACILITY (Maibarara-1) On February 08-27, 2021, the Maibarara-1 facility underwent its scheduled minor maintenance shutdown. Various maintenance activities for the unit’s mechanical, electrical, and instrumentation facilities, as well as for the switchyard and transmission lines, were carried-out by MGI technical staff and private contractors. Replacement works for the wellhead assembly of Maibarara-1 production well MB-12D were also conducted during this maintenance shutdown. On the steamfield side, the two (2) production wells dedicated to Maibarara-1 operations - Mai-6D and MB-12D - continued to behave consistently with dynamic but sustainable production.

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PETROENERGY RESOURCES CORPORATION

MGI conducts regular air and water quality monitoring to ensure compliance with DENR’s standards

MGI’s Material Recovery Facility (MRF)

12 MW MAIBARARA-2 GEOTHERMAL POWER FACILITY

MGI’s butterfly garden installed inside the project site serves as attraction and learning area for visitors

(Maibarara-2) PERC’s second geothermal power station, Maibarara-2, went into commercial operations on April 30, 2018. In 2020, it exported 93.97 GWh of electricity at an average capacity factor of 95.51% and availability factor of 97.04%. On February 08 to13, 2021, the Maibarara-2 facility had its similar scheduled minor maintenance shutdown activities. Maibarara-1 and Maibarara-2 are operated by Maibarara Geothermal Inc (MGI), a joint venture between PERC’s RE subsidiary PetroGreen Energy Corporation (PGEC) (65%), AC Energy Corporation, (25%) and PNOC Renewables Corporation (10%).

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

PROPOSED 14 MW NABAS EXPANSION (Nabas-2) 36MW NABAS-1 WIND POWER FACILITY (Nabas-1)

80.46 GWh

Electricity Exported

26.10%

PWEI ensures continuous re-greening of the wind farm through slope rehabilitation using bio-engineering measures

Capacity Factor

The proposed 14MW Nabas-2 takes advantage of the existing facilities and operational experiences in Nabas-1. After the enactment of the Expanded NIPAS Law (Republic Act 11038) in June 2018, PetroWind Energy Inc. (PWEI) advanced its feasibility works for Nabas-2, which will be located in the multiple-use zone nothern edge of the Northwest Panay Peninsula Natural Park (NWPPNP).

94.15%

Availability Factor

The Northwest Panay Peninsula Natural Park (NWPP)

36 MW NABAS-1 WIND POWER FACILITY (NABAS-1)

PERC’s first windfarm, Nabas-1, went commercial operations on June 10, 2015.

into

In 2020, Nabas-1 exported 80.46 GWh of electricity with average capacity factor of 26.10% and availability factor of 94.15%. To maintain operational efficiency of the windfarm, O&M contractor Siemens-Gamesa Renewable Energy (SGRE) completed its 60-Month (60M) and 66-Month (66M) wind turbine-generator (WTG) maintenance works in June and October 2020, respectively. In parallel, the annual preventive maintenance for the 69-kV electrical facilities was also conducted by Airnergy and Renewables, Inc. from June 13 to 14, 2020.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PWEI’s view deck is envisioned to be a venue to promote renewable energy and responsible tourism to visitors and tourists PWEI contractors conduct preventive maintenance of its electrical facilities

Both wind projects are being operated by PWEI, a joint venture between PGEC (40%), Bangchak Corporation Public Company Ltd. (BCPG) (40%) and EEI Power (20%).

PETROENERGY RESOURCES CORPORATION

50 MWDC TARLAC-1 SOLAR POWER FACILITY (Tarlac-1)

71.93 GWh

Electricity Exported

20.05%

Capacity Factor

20 MWDC TARLAC-2 SOLAR POWER FACILITY (Tarlac-2)

29.75 GWh

Electricity Exported

20.60%

Capacity Factor

PSC’s carport made from recycled solar PV panels

50 MWDC TARLAC-1 SOLAR POWER FACILITY (TARLAC-1)

PERC’s first solar farm, Tarlac-1, started commercial operations on February 10, 2016. In 2020, Tarlac-1 exported a total of 71.93 GWh of electricity at an average capacity factor of 20.05%.

A Tilapia fish pond inside the PSC site, showcases that renewable energy generation co-exists harmoniously with aquaculture.

A greenhouse adjacent to our solar farm shows the benefits of sunlight to both energy generation and food production.

Tarlac-1 performed above forecast in seven (7) months and slightly below forecast in five (5) months of 2020 due to: 1) NGCP grid-related downtime, 2) equipment maintenance, and 3) various meteorological variables. Tarlac-1’s 2020 output was above forecast with capacity factors higher than the industry standards, throughout the year.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

20 MWDC TARLAC-2 SOLAR POWER FACILITY (TARLAC-2)

PERC’s fifth and newest power generating facility, Tarlac-2, is a 20MWDC expansion of the 50 MWDC Tarlac-1, and started exporting power to the grid on April 22, 2019 as part of its commissioning tests. On February 27, 2020 and March 18, 2020, the DOE formally issued to PetroSolar Corporation (PSC) the Certificate of Confirmation of Commerciality (COCOC) and the Certificate of Endorsement (COE) for Tarlac-2,

respectively. The COE is a prerequisite to the issuance of the Certificate of Compliance (COC). To date, PSC is still awaiting the Energy Regulatory Commission (ERC) approval and release of Tarlac-2’s COC, which will determine the official Commercial Operations Date (COD) for Tarlac-2. In 2020, Tarlac-2 exported a total of 29.75 GWh of electricity at an average capacity factor of 20.60%. Tarlac-1 and Tarlac-2 are operated by PSC, a joint venture between PGEC (56%) and EEI Power (44%).

70MWDC Tarlac Solar Power Facility

PROPOSED SAN VICENTE WIND HYBRID POWER PROJECT (SVWPP) DOE SERVICE CONTRACT AREA (10,773 Hectares)

The Wind Energy Service Contract for PGEC’s latest off-grid renewable energy project, the SVWPP, was signed by DOE Secretary Alfonso Cusi on October 09, 2019. The SVWPP aims to put up initially a 5-10 MW off-grid wind-hybrid power facility in San Vicente, Palawan to meet the increasing electricity demand and address the lack of reliable power supply in the town through wind power or a hybrid thereof.

PROPOSED WIND SITES

PGEC will undertake the three-year pre-development stage starting 2020, consisting of: 1) Two-year wind measurement campaign, 2) LGU and regulatory permitting works, and 3) technical and economic feasibility works for a potential wind-hybrid system in San Vicente.

I AL IP

E IC

5-MVA NPC ROXAS SUBSTATION

ENRIQUE T. YUCHENGCO BLDG. ROOFTOP SOLAR POWER PROJECT (ETY) PGEC is currently completing its first commercial and industrial (C&I) rooftop solar project for the Enrique T. Yuchengco Bldg. in Binondo, Manila.

(PALECO). On March 12, 2020, PALECO issued a bulletin postponing the CSP until further notice.

The PPSHPP is a proposed 20 MW solar hybrid power facility intended to address both the escalating power demand in Puerto Princesa City, Palawan and fluctuating electricity supply from the current power providers in the city.

On January 18, 2021, PALECO issued a bulletin resuming the Palawan Main Grid 20-MW CSP after a 10-month postponement, with revisions to the bid terms as approved by the DOE and the National Electrification Administration (NEA). However, PGEC decided to withdraw from said bidding, owing to several restrictions and provisions in PALECO’s final Terms of Reference (TOR), that would make the economic feasibility of PGEC’s planned investment extremely difficult.

PGEC secured all local government endorsements needed for eventual facility development. In January 2020, PGEC was among seven (7) pre-qualified bidders for the 20-MW Palawan Main Grid Competitive Selection Process (CSP) of the Palawan Electric Cooperative 22

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PGEC is now exploring alternative offtake arrangements for the Puerto Princesa solar service contract.

ULUGAN BAY

PROJECT SITE

SERVICE CONTRACT AREA (8,829 HECTARES)

LUZON

VISAYAS SULU SEA

PUERTO PRINCESA

AW AN

PROPOSED PUERTO PRINCESA SOLAR HYBRID POWER PROJECT (PPSHPP)

PA L

ETY solar rooftop project

The building owner E.T. Yuchengco Inc. (ETY) and project owner PGEC signed a 15-year Rent-to-Own Agreement for a 140.8-kWp solar rooftop facility last January 14, 2021. The rental period will commence once the construction of the rooftop facility is completed in 3-4 months. After said 15-year cooperation period, PGEC will turn-over the said rooftop solar facility to ETY.

MINDANAO

PETROENERGY RESOURCES CORPORATION

As its utmost priority, PERC ensured that there were no lay-offs among its workforce. Employees were given the tools to work remotely and safely. Those serving as frontliners, were given the proper protective gears, regular testing, and support to continuously perform their duties and ensure business continuity. PERC allotted a total of US$12,204 for the vaccination program of its employees.

IV.

NO LAY-OFFS

Duty engineer in PSC wears protective mask while doing inspection in switchgear room

US$12,204

Parents of students from Pawa Primary school received PWEI’s donation of school materials for their children

FOR VACCINATION PROGRAM OF EMPLOYEES

PERC likewise extended help to hospitals and host barangays. On September 1, 2020, PERC donated 1,000 pcs of KN95 masks and 500 food packs to Philippine General Hospital (PGH).

PERC’s culture and commitment on social responsibility were expressed even more concretely during this pandemic. Planned CSR projects had to be realigned to focus on immediate pandemic response and help to employees and communities.

MGI conducts air quality monitoring in nearby village

1,000 PCS KN95 MASKS 500 FOOD PACKS PERC donation to Philippine General Hospital (PGH)

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

MGI donated mobile units to Puting Lupa Elementary School

On education, under the Adopt-A-School Program, MGI donated 50 units of mobile phones to Puting Lupa Elementary School, to support modular distance learning and teaching. The mobile phones serve as a tool for students to communicate with their teachers in a hybridlearning system. PERC also partnered with Malayan Colleges Mindanao (MCM), to donate mobile devices (tablets) to Batasan Elementary School in Batasan, Makilala,

PERC, thru Malayan Colleges Mindanao (MCM), donated mobile tablets to Batasan Elementary School in Cotabato

North Cotabato. Turned over last November 23, 2020, the tablets will be used by 127 pupils from Grades 4 to 6 to aid them in their academic needsduring the pandemic and beyond. Pocket WiFis and sim cards donated by Smart Communications were also distributed to the school to complement the learning devices.

Food donation drives to Barangay frontliners in Batangas (above photo), Tarlac (lower left photo), and Aklan ( lower right photo).

Brgy. Pawa children happily post for photo with PWEI’s wind turbine as background

Several food donation drives were conducted in Batangas, Tarlac, and Aklan. Spearhead by PERC CSR Team on each project site, food supplies were donated to frontliners, barangay officials, and health workers, who conduct health monitoring, contact tracing, and health protocols in their respective barangays. The food donation was also extended to indigent families during the Christmas season. 26

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

To cap off last year’s CSR activities, PERC employees participated in the YGC Christmas Fund Drive of AY Foundation. The activity encouraged employees to donate whatever amount they can so the Foundation can

provide food to indigent families during the Christmas season. The donation drive generated a total amount of P19.85 MM from all participating YGC-member companies, including PERC and its subsidiaries. PETROENERGY RESOURCES CORPORATION

BOARD OF DIRECTORS

SENIOR MANAGEMENT & CORPORATE DIRECTORY

VI.

Mr. Eliseo B. Santiago

Cesar A. Buenaventura

Independent Director

Lead Independent Director

Lorenzo V. Tan

Mr. Basil L. Ong

Director

Independent Director

Milagros V. Reyes

Francisco G. Delfin, Jr.

Yvonne S. Yuchengco Treasurer

Corporate Secretary and Corporate Information Officer

Arlan P. Profeta

Maria Victoria M. Olivar

Carlota R. Viray

Paul Elmer C. Morala

President

Vice President

Assistant Corporate Secretary

AVP for Technical Affairs

Samuel V. Torres

AVP for Finance

AVP for Plant Operations

CORPORATE DIRECTORY AUDITOR

BANKER

TRANSFER AGENT

SyCip Gorres Velayo & Co. 6760 Ayala Ave., 1226 Makati City

Rizal Commercial Banking Corporation G/F Ortigas Malayan Plaza Cor. Opal Road, ADB Avenue, Ortigas Center,

Rizal Commercial Banking Corporation G/F Grepalife Building, Gil J. Puyat Ave., Makati CIty T: (632) 892-4156 / 892-1416

Pasig City

CORPORATE OFFICE Yvonne S. Yuchengco Director and Treasurer

Helen Y. Dee Chairman

Milagros V. Reyes

Director and President

PetroEnergy Resources Corporation 7F JMT Corporate Building, ADB Avenue, Ortigas Center, Pasig City

T: (632) 637-2917 / 637-5799 / 637-4032 / 637-4362 F: (632) 634-6066 / 633-8584 Website: http://www.petroenergy.com.ph Follow: @PERCGroupPH in

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

VII.

CONSOLIDATED FINANCIAL STATEMENTS

DESCO rig during the preventive maintenance in MGI steamfield

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

SyCip Gorres Velayo & Co. 6760 Ayala Avenue 1226 Makati City Philippines

Tel: (632) 8891 0307 Fax: (632) 8819 0872 ey.com/ph

BOA/PRC Reg. No. 0001, October 4, 2018, valid until August 24, 2021 SEC Accreditation No. 0012-FR-5 (Group A), November 6, 2018, valid until November 5, 2021

-2We have fulfilled the responsibilities described in the Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying consolidated financial statements.

INDEPENDENT AUDITOR’S REPORT

The Board of Directors and Stockholders PetroEnergy Resources Corporation 7th Floor, JMT Building, ADB Avenue Ortigas Center, Pasig City

Estimation of oil reserves

Opinion We have audited the consolidated financial statements of PetroEnergy Resources Corporation and its subsidiaries (the Group), which comprise the consolidated statements of financial position as at December 31, 2020 and 2019, and the consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated statements of cash flows for each of the three years in the period ended December 31, 2020, and notes to the consolidated financial statements, including a summary of significant accounting policies.

The estimation oil reserves is a focus area because the resulting estimates have a material impact on the consolidated financial statements, as these are utilized in the impairment testing and the calculation of depletion expense of the investments in Gabon, West Africa. Wells, platforms and other facilities which are depleted are presented under Property, plant and equipment amounting to = P557.77 million as of December 31, 2020. There are inherent uncertainties involved in estimating oil reserve quantities because of the exercise of significant management judgment and consideration of inputs from internal geologists and the complex contractual arrangements involved as regards the Group’s share of reserves in the exploration and production sharing contract areas. This uncertainty also depends on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Group as at December 31, 2020 and 2019, and its consolidated financial performance and its consolidated cash flows for each of the three years in the period ended December 31, 2020 in accordance with Philippine Financial Reporting Standards (PFRSs).

The disclosures in relation to oil reserves are included in Notes 5 and 10 to the consolidated financial statements.

Basis for Opinion

We considered the competence, capabilities and objectivity of the geologists engaged by the Group to perform an independent assessment of its oil reserves given their qualifications, experience and reporting responsibilities. We reviewed the specialist’s report and obtained an understanding of the nature, scope and objectives of his work and basis of the estimates including any changes in the reserves during the year. In addition, we tested the reserves estimates applied to the relevant areas of the consolidated financial statements including impairment testing and recognition of depletion expense.

We conducted our audits in accordance with Philippine Standards on Auditing (PSAs). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are independent of the Group in accordance with the Code of Ethics for Professional Accountants in the Philippines (Code of Ethics) together with the ethical requirements that are relevant to our audit of the consolidated financial statements in the Philippines, and we have fulfilled our other ethical responsibilities in accordance with these requirements and the Code of Ethics. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key Audit Matters Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the consolidated financial statements of the current period. These matters were addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context.

Audit response

Recoverability of investments in Gabon, West Africa The Group has significant investments in Gabon, West Africa consisting of wells, platforms and other facilities which are presented under Property, plant and equipment, production license presented under Intangible assets and Deferred oil exploration costs. The recoverability of these assets, with carrying amount aggregating to P =618.07 million as of December 31, 2020, is affected by low crude oil prices and political risks, among others, and that are tested for impairment when there are indications that the carrying values of these investments may exceed their recoverable amounts. The assessment of the recoverable amount of these investments requires significant judgment and involves estimation using assumptions about future production levels and costs, as well as external inputs such as oil prices and discount rate. Hence, such assessment is a key audit matter in our audit. The disclosures in relation to the Group’s investments in Gabon, West Africa are included in Notes 5, 10, 11 and 15 to the consolidated financial statements.

*SGVFSM008891* A member firm of Ernst & Young Global Limited

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891* A member firm of Ernst & Young Global Limited

PETROENERGY RESOURCES CORPORATION

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Audit response We involved our internal specialist in evaluating the methodologies and the assumptions used. These assumptions include future production levels and costs, as well as external inputs such as oil prices and discount rate. We compared the key assumptions used such as future production levels against oil reserves and costs against historical data. We tested the parameters used in the determination of the oil prices and discount rate against market data. We also reviewed the Group’s disclosures about those assumptions to which the outcome of the impairment test is most sensitive, specifically those that have the most significant effect in the determination of the recoverable amounts of these investments. Estimation of asset retirement obligations The Group has provisions for the close-down, restoration and environmental obligations on its solar power plant in Tarlac, geothermal power plant in Batangas and interest in oil fields in Gabon totaling to P109.16 million as of December 31, 2020. The Group uses an external technical specialist to assess its share in abandonment cost in the Gabon oil fields, and an internal technical group to estimate the future restoration costs of its solar and geothermal power plant sites. The estimation of the provisions requires significant management judgment in estimating future costs given the nature of each site, the operating activities done, and the facilities constructed, among other considerations. This calculation also requires the management to use a discount and inflation rates for these future costs to bring them to their present value at reporting date. The Group’s disclosures about asset retirement obligations are included in Notes 5 and 18 to the consolidated financial statements. Audit response We considered the competence, capabilities and objectivity of management’s internal and external technical specialists given their qualifications, experience and reporting responsibilities. We reviewed the decommissioning report and obtained an understanding from the internal and external technical specialists about their bases for identifying and estimating the Group’s share in abandonment costs in the Gabon oil fields and restoration costs of its solar and geothermal power plant sites. We also evaluated the discount and inflation rates used by comparing these to external data. We also reviewed the Group’s disclosures on the assumptions that have the most significant effect in the determination of the amounts of these obligations.

In connection with our audits of the consolidated financial statements, our responsibility is to read the other information identified above when it becomes available and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audits, or otherwise appears to be materially misstated. Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with PFRSs, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. In preparing the consolidated financial statements, management is responsible for assessing the Group’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so. Those charged with governance are responsible for overseeing the Group’s financial reporting process. Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with PSAs will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements. As part of an audit in accordance with PSAs, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: 

Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.



Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control.



Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.

Other Information Management is responsible for the other information. The other information comprises the information included in the SEC Form 20-IS (Definitive Information Statement), SEC Form 17-A and Annual Report for the year ended December 31, 2019, but does not include the consolidated financial statements and our auditor’s report thereon. The SEC Form 20-IS (Definitive Information Statement), SEC Form 17-A and Annual Report for the year ended December 31, 2020 are expected to be made available to us after the date of this auditor’s report. Our opinion on the consolidated financial statements does not cover the other information and we will not express any form of assurance conclusion thereon.

*SGVFSM008891* A member firm of Ernst & Young Global Limited

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891* A member firm of Ernst & Young Global Limited

PETROENERGY RESOURCES CORPORATION

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-4-



Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.



Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the audit. We remain solely responsible for our audit opinion.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with PFRSs, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

In preparing the consolidated financial statements, management is responsible for assessing the Group’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the consolidated financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

Those charged with governance are responsible for overseeing the Group’s financial reporting process.

The engagement partner on the audit resulting in this independent auditor’s report is Ana Lea C. Bergado. SYCIP GORRES VELAYO & CO.

Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with PSAs will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements. As part of an audit in accordance with PSAs, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

Ana Lea C. Bergado Partner CPA Certificate No. 80470 SEC Accreditation No. 0660-AR-4 (Group A), October 22, 2019, valid until October 21, 2022 Tax Identification No. 102-082-670 BIR Accreditation No. 08-001998-063-2020, November 27, 2020, valid until November 26, 2023 PTR No. 8534225, January 4, 2021, Makati City



April 23, 2021



Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.

*SGVFSM008891* A member firm of Ernst & Young Global Limited

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891* A member firm of Ernst & Young Global Limited

PETROENERGY RESOURCES CORPORATION

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PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

2020 REVENUES Electricity sales (Notes 4 and 33) Oil revenues (Note 33) COST OF SALES Cost of electricity sales (Note 21) Oil production (Note 22) Depletion (Note 10) Change in crude oil inventory (Notes 4 and 22)

P =2,039,917,873 292,573,199 2,332,491,072

2020 NET INCOME ATTRIBUTABLE TO: Equity holders of the Parent Company Non-controlling interests (Note 29)

Years Ended December 31 2019 =1,771,107,457 P 351,057,274 2,122,164,731

2018

=1,725,156,936 P 436,971,279 2,162,128,215

909,577,258 211,527,791 82,236,533 (23,926,774) 1,179,414,808

805,694,582 221,259,356 55,845,199 (2,371,818) 1,080,427,319

721,184,272 242,695,131 81,096,112 22,803,652 1,067,779,167

1,153,076,264

1,041,737,412

1,094,349,048

211,402,211

223,213,616

217,463,499

(386,788,348) 111,266,383 18,362,302 (4,129,022) (3,500,604)

(409,690,469) 97,552,085 44,025,392 (4,505,825) (7,232,114)

(388,377,540) 118,849,158 43,860,614 (4,309,762) 6,070,411

(708,509) ‒ 11,876,677 (253,621,121)

(242,610) ‒ 7,682,215 (272,411,326)

(575,624) 54,317,979 6,354,982 (163,809,782)

INCOME BEFORE INCOME TAX

688,052,932

546,112,470

713,075,767

PROVISION FOR INCOME TAX (Note 20)

41,861,712

12,179,814

18,162,480

646,191,220

533,932,656

694,913,287

‒

24,653,465

GROSS INCOME GENERAL AND ADMINISTRATIVE EXPENSES (Note 23) OTHER INCOME (CHARGES) – Net Interest expense (Notes 13 and 17) Share in net income of a joint venture (Note 12) Interest income (Notes 6, 7, 9 and 33) Accretion expense (Note 18) Net foreign exchange gains (losses) Fair value changes on financial assets at fair value through profit or loss (Note 8) Impairment reversal (Notes 10 and 11) Miscellaneous income (Note 24)

NET INCOME OTHER COMPREHENSIVE INCOME (LOSS) Item that may be reclassified to profit or loss in subsequent periods Movements in cumulative translation adjustment - net of tax (Note 19) Item not to be reclassified to profit or loss in subsequent periods Remeasurement gains (losses) on net accrued retirement liability - net of tax Share in other comprehensive income of a joint venture (Note 12) TOTAL OTHER COMPREHENSIVE INCOME (LOSS) TOTAL COMPREHENSIVE INCOME

(1,798,279) 214,758 (1,583,521) P =644,607,699

(4,939,493)

3,451,605

(507,474)

‒

(5,446,967)

28,105,070

=528,485,689 P

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO: Equity holders of the Parent Company Non-controlling interests (Note 29) EARNINGS PER SHARE FOR NET INCOME ATTRIBUTABLE TO EQUITY HOLDERS OF THE PARENT COMPANY - BASIC AND DILUTED (Note 28)

Years Ended December 31 2019

2018

P =319,412,421 326,778,799 P =646,191,220

P292,835,761 = 241,096,895 =533,932,656 P

P421,257,530 = 273,655,757 =694,913,287 P

P =320,344,697 324,263,002 P =644,607,699

P289,002,268 = 239,483,421 =528,485,689 P

P449,219,204 = 273,799,153 =723,018,357 P

P =0.5616

=0.5149 P

=0.7407 P

See accompanying Notes to Consolidated Financial Statements.

=723,018,357 P

(Forward)

*SGVFSM008891* 38

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

40 SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT ‒ ‒ ‒ ‒ 568,711,842 2,156,679,049 ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ = P568,711,842 = P2,156,679,049

See accompanying Notes to Consolidated Financial Statements

BALANCES AT DECEMBER 31, 2017 Net income Remeasurement gain on net accrued retirement liability Movement in cumulative translation adjustment Total comprehensive income Issuance of stocks Cash dividends Reversal of appropriation Increase in non-controlling interests: Deposit for future stock subscriptions Stock issuances BALANCES AT DECEMBER 31, 2018 Net income Remeasurement loss on net accrued retirement liability Share in OCI of a joint venture Total comprehensive income (loss) Cash dividends Increase in non-controlling interests - stock issuances (excluding previous deposits for future stock subscriptions issued during the year) Derecognition of deferred tax assets BALANCES AT DECEMBER 31, 2019 Net income Remeasurement loss on net accrued retirement liability Share in OCI of a joint venture Total comprehensive income Cash dividends BALANCES AT DECEMBER 31, 2020 ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ =‒ P

‒ (353,707) 2,017,651,639 319,412,421 ‒ ‒ 319,412,421 ‒ = P2,337,064,060

‒ ‒ (9,663,958) ‒ 738,994 ‒ 738,994 ‒ (P = 8,924,964)

‒ ‒ ‒ ‒ (456,727) 114,499,681 ‒ ‒ ‒ ‒ 193,282 ‒ 193,282 ‒ ‒ ‒ (P = 263,445) = P114,499,681

Attributable to Equity Holders of the Parent Company Cumulative Appropriated Unappropriated Remeasurement Translation Retained of Net Accrued Share in OCI of Retained Additional Adjustment Retirement a Joint Venture Earnings Earnings Capital Stock Paid-in Capital (Note 19) (Note 19) (Note 19) (Note 19) Liability (Note 12) (Note 19) = P410,736,330 = P1,556,372,104 = P138,589,220 = P1,193,758,427 (P = 9,595,401) =‒ = P P89,846,216 ‒ ‒ ‒ 421,257,530 ‒ ‒ ‒ ‒ ‒ ‒ ‒ 3,308,209 ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ 24,653,465 ‒ ‒ ‒ 421,257,530 3,308,209 ‒ 24,653,465 157,975,512 600,306,945 ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ (28,435,592) ‒ ‒ ‒ ‒ ‒ (138,589,220) 138,589,220 ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒ 568,711,842 2,156,679,049 ‒ 1,725,169,585 (6,287,192) ‒ 114,499,681 ‒ ‒ ‒ 292,835,761 ‒ ‒ ‒ ‒ ‒ ‒ ‒ (3,376,766) ‒ ‒ ‒ ‒ ‒ ‒ ‒ (456,727) ‒ ‒ ‒ ‒ 292,835,761 (3,376,766) (456,727) ‒ ‒ ‒ ‒ ‒ ‒ ‒ ‒

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

‒ ‒ 4,638,822,203 292,835,761 (3,376,766) (456,727) 289,002,268 ‒

197,398,447 12,500,000 2,008,296,872 241,096,895 (1,562,727) (50,747) 239,483,421 (76,000,000)

197,398,447 12,500,000 6,647,119,075 533,932,656 (4,939,493) (507,474) 528,485,689 (76,000,000)

*SGVFSM008891*

‒ ‒ 166,907,053 166,907,053 ‒ (353,707) (348,094) (701,801) 80,049,238 4,927,470,764 2,338,339,252 7,265,810,016 ‒ 319,412,421 326,778,799 646,191,220 ‒ 738,994 (2,537,273) (1,798,279) ‒ 193,282 21,476 214,758 ‒ 320,344,697 324,263,002 644,607,699 ‒ ‒ (79,500,000) (79,500,000) = P80,049,238 = P5,247,815,461 = P2,583,102,254 = P7,830,917,715

‒ ‒ 80,049,238 ‒ ‒ ‒ ‒ ‒

Equity Non-controlling Reserve Interests (Note 19) Total (Note 29) Total = P80,049,238 = P3,459,756,134 = P1,590,499,272 = P5,050,255,406 ‒ 421,257,530 273,655,757 694,913,287 ‒ 3,308,209 143,396 3,451,605 ‒ 24,653,465 ‒ 24,653,465 ‒ 449,219,204 273,799,153 723,018,357 ‒ 758,282,457 ‒ 758,282,457 ‒ (28,435,592) (65,900,000) (94,335,592) ‒ ‒ ‒ ‒

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

CASH FLOWS FROM OPERATING ACTIVITIES Income before income tax Adjustments for: Depletion, depreciation and amortization (Notes 10, 13 and 15) Interest expense (Notes 13 and 17) Share in net income of a joint venture (Note 12) Interest income (Notes 6, 7 and 9) Provision for probable losses (Note 23) Write-off of deferred development costs (Note 15) Accretion expense (Note 18) Movement in accrued retirement liability Net unrealized foreign exchange loss (gain) Fair value changes on financial assets at fair value through profit or loss (Note 8) Gain on sale of equipment (Note 24) Dividend income (Note 8) Impairment reversal (Notes 10 and 11) Operating income before working capital changes Decrease (increase) in: Receivables Contract asset (Note 33) Input VAT Other current assets Increase in accounts payable and accrued expenses Cash generated from operations Interest received Income taxes paid, including movement in creditable withholding taxes Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES Payments for: Acquisitions of property, plant and equipment (Note 10) Deferred oil exploration costs (Note 11) Deferred development costs (Note 15) Acquisitions of intangibles (Note 15) Advances to contractors (Note 15) Dividends received (Notes 8 and 12) Proceeds from sale of property, plant and equipment Withdrawal from (contribution to) restricted cash (Note 9) Decrease (increase) in other noncurrent assets Net cash used in investing activities 2020

=688,052,932 P

Years Ended December 31 2019

=546,112,470 P

2018

= P713,075,767

529,123,431 386,788,348 (111,266,383) (18,362,302) 14,667,316 5,959,962 4,129,022 (3,018,565) 816,741 486,048,073 409,690,469 (97,552,085) (44,025,392) 6,188,034 ‒ 4,505,825 (397,681) 4,884,642 434,796,786 388,377,540 (118,849,158) (43,860,614) 12,553,048 ‒ 4,309,762 3,227,826 (6,070,411)

708,509 (662,857) (71,770) ‒ 1,496,864,384 242,610 (345,134) (61,586) ‒ 1,315,290,245 575,624 (500,830) (83,050) (54,317,979) 1,333,234,311

59,857,904 (132,687,182) 2,915,446 10,638,198 56,274,625 1,493,863,375 19,280,794 22,257,025 ‒ 74,834,553 (151,914,259) 19,522,566 1,279,990,130 44,531,743 29,555,146 ‒ 4,277,486 (191,380,576) 78,792,689 1,254,479,056 47,208,947

(33,966,707) 1,479,177,462 (16,194,063) 1,308,327,810 (15,200,938) 1,286,487,065

(219,209,060) (39,915,658) (3,210,454) (2,102,105) ‒ 40,071,770 825,000 ‒ 3,577,849 (219,962,658) (941,313,683) (19,606,158) (39,144,180) (9,821,503) (29,300,000) 60,061,586 1,839,579 160,000,000 96,167,613 (721,116,746) (117,710,922) (47,680,995) (61,165,900) (17,171,106) ‒ 83,050 500,831 (303,666,050) (183,720,035) (730,531,127)

(Forward)

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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2020

CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Availments of debt - net of deferred financing costs (Note 17) Issuance of stocks to non-controlling interests (Note 29) Deposits for future stock subscriptions on non-controlling interests (Note 29) Issuance of stocks by the Parent Company (Note 19) Payments of: Loans (Notes 17 and 30) Interest (Notes 17 and 30) Dividends to non-controlling interests (Notes 29 and 30) Lease liabilities (Note 13) Dividends by the Parent Company (Note 19) Net cash used in financing activities

(1,369,699,350) (348,317,765) (79,500,000) (36,596,442) ‒ (1,057,764,095)

NET EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS

(816,742)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR CASH AND CASH EQUIVALENTS AT END OF YEAR (Note 6)

Years Ended December 31 2019

2018

=776,349,462 P ‒

P546,347,841 = 166,907,053

=317,804,356 P 12,500,000

‒ ‒

197,398,447 758,282,457

200,633,967 1,066,698,077

(940,520,781) (1,177,263,636) (364,125,100) (396,054,782) (76,000,000) (65,900,000) (36,338,378) ‒ (9,500) (28,435,592) (703,738,865) (381,668,750) (4,884,642)

9,702,056

(121,412,443)

183,989,244

1,188,110,520

1,004,121,276

=1,267,332,044 P P =1,066,698,077 P =1,188,110,520

See accompanying Notes to Consolidated Financial Statements.

PETROENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Corporate Information a. Organization PetroEnergy Resources Corporation (“PERC” or “PetroEnergy” or the “Parent Company”) is a publicly-listed domestic corporation. Its registered office and principal place of business is 7th Floor, JMT Building, ADB Avenue, Ortigas Center, Pasig City. PERC was organized on September 29, 1994 as Petrotech Consultants, Inc. to provide specialized technical services to its then parent company, Petrofields Corporation, and to companies exploring for oil in the Philippines. In 1997, PERC simultaneously adopted its present name and changed its primary purpose to oil exploration and development and mining activities. Subsequently in 1999, PERC assumed Petrofields’ oil exploration contracts in the Philippines and the Production Sharing Contract covering the Etame discovery block in Gabon, West Africa. On August 11, 2004, PERC’s shares of stock were listed at the Philippine Stock Exchange (PSE) by way of introduction. In 2009, following the enactment of Republic Act No. 9513, otherwise known as the “Renewable Energy Act of 2008” (RE Law), PERC amended its articles of incorporation to include among its purposes the business of generating power from renewable sources such as, but not limited to, biomass, hydro, solar, wind, geothermal, ocean and such other renewable sources of power. On March 31, 2010, PERC incorporated PetroGreen Energy Corporation (“PetroGreen” or “PGEC”), its 90%-owned subsidiary, to act as its renewable energy arm and holding company. PGEC ventured into renewable energy development and power generation through its subsidiaries and affiliate: (a) Maibarara Geothermal, Inc. (“MGI”, 65%-owned) - owner and Renewable Energy (RE) developer of the 20 MW Maibarara Geothermal Power Project (MGPP-1) in Santo Tomas, Batangas and its expansion, the 12 MW MGPP-2; (b) PetroSolar Corporation (“PetroSolar”, 56%owned) - owner and RE developer of the 50 MWDC Tarlac Solar Power Project (TSPP-1) in Tarlac City and its 20 MWDC expansion (TSPP-2); and (c) PetroWind Energy, Inc. (“PetroWind”, 40%owned associate) - owner and developer of the 36 MW Nabas Wind Power Project (NWPP-1) in Nabas and Malay, Aklan. MGI and PetroSolar are effectively indirect subsidiaries of PetroEnergy through PetroGreen. PetroGreen owns majority of the voting power of MGI and PetroSolar. PetroEnergy, PetroGreen, MGI and PetroSolar are collectively referred to as the “Group” and were incorporated in the Philippines. b. Nature of Operations The Group’s four (4) main energy businesses are: (a) upstream oil exploration and development, and power generation from renewable energy resources such as, (b) geothermal, (c) solar, and (d) wind, through the Group’s affiliate, PetroWind. Upstream Oil Exploration and Development Petroleum production is on-going in the Etame (Gabon) concession, while the other petroleum concessions in the Philippines are still in the advanced exploration stages or pre-development stages.

*SGVFSM008891* 42

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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-3-

Geothermal Energy The geothermal projects are the 20 MW MGPP-1 in Sto. Tomas, Batangas that started commercial operations on February 8, 2014 and its expansion, the 12 MW MGPP-2 that started commercial operations on April 30, 2018.

including all of the inputs and processes needed to create outputs. These amendments may impact future periods should the Group enter into any business combinations. 

Solar Energy The Solar power projects are the 50 MWDC TSPP-1 in Tarlac City, Tarlac that started commercial operations on February 10, 2016 and its 20 MWDC expansion (TSPP-2) which has been commissioned and tested on April 22, 2019 and is now awaiting the issuance of a Certificate of Compliance (COC) from the Energy Regulatory Commission (ERC).

The amendments provide a new definition of material that states “information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.”

Wind Energy The wind energy project is the 36-MW NWPP-1 in Nabas, Aklan, where PetroWind has a wind farm. It started its commercial operations on June 10, 2015. c.

Approval of Consolidated Financial Statements The accompanying consolidated financial statements were approved and authorized for issue by the Board of Directors (BOD) on April 23, 2021.

2. Basis of Preparation Basis of Preparation The accompanying consolidated financial statements have been prepared under the historical cost basis, except for financial assets carried at fair value through profit or loss (FVTPL) which are measured at fair value and crude oil inventory which is valued at net realizable value (NRV).

The amendments clarify that materiality will depend on the nature or magnitude of information, either individually or in combination with other information, in the context of the financial statements. A misstatement of information is material if it could reasonably be expected to influence decisions made by the primary users. 

Conceptual Framework for Financial Reporting issued on March 29, 2018 The Conceptual Framework is not a standard, and none of the concepts contained therein override the concepts or requirements in any standard. The purpose of the Conceptual Framework is to assist the standard-setters in developing standards, to help preparers develop consistent accounting policies where there is no applicable standard in place and to assist all parties to understand and interpret the standards. The revised Conceptual Framework includes new concepts, provides updated definitions and recognition criteria for assets and liabilities and clarifies some important concepts.

The financial statements are presented in Philippine Peso (PHP or = P), which is the Parent Company’s functional currency. All amounts are rounded to the nearest PHP unless otherwise stated.

Pronouncements issued but not yet effective are listed below. The Group does not expect that the future adoption of the said pronouncements to have a significant impact on its financial statements.

Statement of Compliance The accompanying consolidated financial statements have been prepared in compliance with Philippine Financial Reporting Standards (PFRS).

Effective beginning on or after January 1, 2021  Amendments to PFRS 9, PFRS 7, PFRS 4 and PFRS 16, Interest Rate Benchmark Reform Phase 2

3. Changes in Accounting Policies The accounting policies adopted are consistent with those of the previous financial year, except that the Group has adopted the following new accounting pronouncements starting January 1, 2020. Adoption of these pronouncements did not have any significant impact on the Group’s financial position or performance.

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Amendments to PFRS 7, Financial Instruments: Disclosures and PFRS 9, Financial Instruments, Interest Rate Amendments to PFRS 16, COVID-19-related Rent Concessions

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Amendments to PFRS 3, Business Combinations, Definition of a Business

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Amendments to PAS 1, Presentation of Financial Statements, and PAS 8, Accounting Policies, Changes in Accounting Estimates and Errors, Definition of Material

The amendments provide the following temporary reliefs which address the financial reporting effects when an interbank offered rate (IBOR) is replaced with an alternative nearly risk-free interest rate (RFR): • Practical expedient for changes in the basis for determining the contractual cash flows as a result of IBOR reform • Relief from discontinuing hedging relationships • Relief from the separately identifiable requirement when an RFR instrument is designated as a hedge of a risk component The Group shall also disclose information about: • The about the nature and extent of risks to which the entity is exposed arising from financial instruments subject to IBOR reform, and how the entity manages those risks; and • Their progress in completing the transition to alternative benchmark rates, and how the entity is managing that transition

The amendments to PFRS 3 clarifies that to be considered a business, an integrated set of activities and assets must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output. Furthermore, it clarifies that a business can exist without

The amendments are effective for annual reporting periods beginning on or after January 1, 2021 and apply retrospectively, however, the Group is not required to restate prior periods.

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Effective beginning on or after January 1, 2022 



Amendments to PFRS 3, Reference to the Conceptual Framework

Annual Improvements to PFRSs 2018-2020 Cycle • Amendments to PFRS 1, First-time Adoption of Philippines Financial Reporting Standards, Subsidiary as a first-time adopter

The amendments are intended to replace a reference to the Framework for the Preparation and Presentation of Financial Statements, issued in 1989, with a reference to the Conceptual Framework for Financial Reporting issued in March 2018 without significantly changing its requirements. The amendments added an exception to the recognition principle of PFRS 3, Business Combinations to avoid the issue of potential ‘day 2’gains or losses arising for liabilities and contingent liabilities that would be within the scope of PAS 37, Provisions, Contingent Liabilities and Contingent Assets or Philippine-IFRIC 21, Levies, if incurred separately. At the same time, the amendments add a new paragraph to PFRS 3 to clarify that contingent assets do not qualify for recognition at the acquisition date.

The amendment permits a subsidiary that elects to apply paragraph D16(a) of PFRS 1 to measure cumulative translation differences using the amounts reported by the parent, based on the parent’s date of transition to PFRS. This amendment is also applied to an associate or joint venture that elects to apply paragraph D16(a) of PFRS 1. The amendment is effective for annual reporting periods beginning on or after January 1, 2022 with earlier adoption permitted. The amendments are not expected to have a material impact on the Group. •

The amendments are effective for annual reporting periods beginning on or after January 1, 2022 and apply prospectively. 

The amendment clarifies the fees that an entity includes when assessing whether the terms of a new or modified financial liability are substantially different from the terms of the original financial liability. These fees include only those paid or received between the borrower and the lender, including fees paid or received by either the borrower or lender on the other’s behalf. An entity applies the amendment to financial liabilities that are modified or exchanged on or after the beginning of the annual reporting period in which the entity first applies the amendment.

Amendments to PAS 16 , Plant and Equipment: Proceeds before Intended Use The amendments prohibit entities deducting from the cost of an item of property, plant and equipment, any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in the manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the costs of producing those items, in profit or loss. The amendment is effective for annual reporting periods beginning on or after January 1, 2022 and must be applied retrospectively to items of property, plant and equipment made available for use on or after the beginning of the earliest period presented when the entity first applies the amendment. The amendments are not expected to have a material impact on the Group.

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Amendments to PAS 37, Onerous Contracts - Costs of Fulfilling a Contract The amendments specify which costs an entity needs to include when assessing whether a contract is onerous or loss-making. The amendments apply a “directly related cost approach”. The costs that relate directly to a contract to provide goods or services include both incremental costs and an allocation of costs directly related to contract activities. General and administrative costs do not relate directly to a contract and are excluded unless they are explicitly chargeable to the counterparty under the contract. The amendments are effective for annual reporting periods beginning on or after January 1, 2022. The amendments are not expected to have a material impact on the Group.

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Amendments to PFRS 9, Financial Instruments, Fees in the ’10 per cent’ test for derecognition of financial liabilities

The amendment is effective for annual reporting periods beginning on or after January 1, 2022 with earlier adoption permitted. The Group will apply the amendments to financial liabilities that are modified or exchanged on or after the beginning of the annual reporting period in which the entity first applies the amendment. The amendments are not expected to have a material impact on the Group. •

Amendments to PAS 41, Agriculture, Taxation in fair value measurements The amendment removes the requirement in paragraph 22 of PAS 41 that entities exclude cash flows for taxation when measuring the fair value of assets within the scope of PAS 41. An entity applies the amendment prospectively to fair value measurements on or after the beginning of the first annual reporting period beginning on or after January 1, 2022 with earlier adoption permitted. The amendments are not expected to have a material impact on the Group.

Effective beginning on or after January 1, 2023  Amendments to PAS 1, Classification of Liabilities as Current or Non-current The amendments clarify paragraphs 69 to 76 of PAS 1, Presentation of Financial Statements, to specify the requirements for classifying liabilities as current or non-current. The amendments clarify: • What is meant by a right to defer settlement • That a right to defer must exist at the end of the reporting period • That classification is unaffected by the likelihood that an entity will exercise its deferral right

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That only if an embedded derivative in a convertible liability is itself an equity instrument would the terms of a liability not impact its classification

The amendments are effective for annual reporting periods beginning on or after January 1, 2023 and must be applied retrospectively. The Group is currently assessing the impact the amendments will have on current practice and whether existing loan agreements may require renegotiation. 

PFRS 17, Insurance Contracts PFRS 17 is a comprehensive new accounting standard for insurance contracts covering recognition and measurement, presentation and disclosure. Once effective, PFRS 17 will replace PFRS 4, Insurance Contracts. This new standard on insurance contracts applies to all types of insurance contracts (i.e., life, non-life, direct insurance and re-insurance), regardless of the type of entities that issue them, as well as to certain guarantees and financial instruments with discretionary participation features. A few scope exceptions will apply. The overall objective of PFRS 17 is to provide an accounting model for insurance contracts that is more useful and consistent for insurers. In contrast to the requirements in PFRS 4, which are largely based on grandfathering previous local accounting policies, PFRS 17 provides a comprehensive model for insurance contracts, covering all relevant accounting aspects. The core of PFRS 17 is the general model, supplemented by: • A specific adaptation for contracts with direct participation features (the variable fee approach) • A simplified approach (the premium allocation approach) mainly for short-duration contracts PFRS 17 is effective for reporting periods beginning on or after January 1, 2023, with comparative figures required. Early application is permitted. The adoption is not applicable to the Group since none of the entities within the Group have activities that are predominantly connected with insurance or issue insurance contracts.

Deferred effectivity  Amendments to PFRS 10, Consolidated Financial Statements, and PAS 28, Sale or Contribution of Assets between an Investor and its Associate or Joint Venture The amendments address the conflict between PFRS 10 and PAS 28 in dealing with the loss of control of a subsidiary that is sold or contributed to an associate or joint venture. The amendments clarify that a full gain or loss is recognized when a transfer to an associate or joint venture involves a business as defined in PFRS 3. Any gain or loss resulting from the sale or contribution of assets that does not constitute a business, however, is recognized only to the extent of unrelated investors’ interests in the associate or joint venture. On January 13, 2016, the Financial Reporting Standards Council deferred the original effective date of January 1, 2016 of the said amendments until the International Accounting Standards Board (IASB) completes its broader review of the research project on equity accounting that may result in the simplification of accounting for such transactions and of other aspects of accounting for associates and joint ventures.

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The Group continues to assess the impact of the above new and amended accounting standards and interpretations effective subsequent to 2020 on the Group’s financial statements in the period of initial application. Additional disclosures required by these amendments will be included in the financial statements when these amendments are adopted. 4. Summary of Significant Accounting Policies Basis of Consolidation The consolidated financial statements comprise the financial statements of the Group as at December 31, 2020 and 2019 and for each of the three years in the period ended December 31, 2020. The financial statements of the subsidiaries are prepared in the same reporting year as the Group’s, using consistent accounting policies. Below are the Group’s subsidiaries, which are all incorporated in the Philippines, with their respective percentage ownership as of December 31, 2020, 2019 and 2018: PetroGreen Percentage share of PetroGreen in its subsidiaries: MGI PetroSolar Navy Road Development Corporation (NRDC) – dormant company

90% 65% 56% 100%

Subsidiaries are entities controlled by PERC. PERC controls an investee if and only if PERC has: a) power over the investee (i.e. existing rights that give it the current ability to direct the relevant activities of the investee); b) exposure, or rights, to variable returns from its involvement with the investee; and c) the ability to use its power over the investee the amount of the investor’s returns. When PERC has less than a majority of the voting or similar rights of an investee, PERC considers all relevant facts and circumstances in assessing whether it has power over an investee, including: a) the contractual arrangement with the other vote holders of the investee; b) rights arising from other contractual arrangements; and c) the Group’s voting rights and potential voting rights. PERC re-assesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control. Consolidations of a subsidiary begins when PERC obtains control over the subsidiary and ceases when PERC loses control of the subsidiary. Assets, liabilities, income and expenses of a subsidiary acquired or disposed of during the year are included in the consolidated statement of comprehensive income from the date PERC gains control until the date PERC ceases to control the subsidiary. The consolidated financial statements are prepared using uniform accounting policies for like transactions and other events in similar circumstances. Adjustments where necessary are made to ensure consistency with the policies adopted by the Group. All intra-group balances and transactions, intragroup profits and expenses and gains and losses are eliminated during consolidation. All intra-group balances, transactions, income and expenses and profit and losses are eliminated in full.

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A change in the ownership interest of a subsidiary, without loss of control, is accounted for as an equity transaction, as transactions with the owners in their capacity as owners. For purchases from noncontrolling interests, the difference between any consideration paid and the relevant share acquired of the carrying value of net assets of the subsidiary is recorded in equity. Gains or losses on disposals to non-controlling interests are also recorded in equity.

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If the Group loses control over a subsidiary, it:

Financial assets at amortized cost (debt instruments) This category is the most relevant to the Group. The Group measures financial assets at amortized cost if both of the following conditions are met:

  

derecognizes the assets (including goodwill) and liabilities of the subsidiary, the carrying amount of any non-controlling interest and the cumulative translation differences recorded in equity. recognizes the fair value of the consideration received, the fair value of any investment retained and any surplus or deficit in the consolidated statement of comprehensive income. reclassifies the parent’s share of components previously recognized in other comprehensive income (OCI) to the consolidated statement of comprehensive income or retained earnings, as appropriate.

Non-controlling interests are presented separately from the Parent Company’s equity. The portion of profit or loss and net assets in subsidiaries not wholly owned are presented separately in the consolidated statement of comprehensive income and consolidated statement of changes in equity, and within equity in the consolidated statement of financial position. Cash and Cash Equivalents Cash includes cash on hand and in banks. Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash with original maturities of three (3) months or less from the dates of acquisition and that are subject to an insignificant risk of change in value. Financial Instruments A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial assets - Initial recognition and measurement Financial assets are classified, at initial recognition, as subsequently measured at amortized cost, fair value through other comprehensive income (FVOCI), and FVTPL. The classification of financial assets at initial recognition depends on the financial asset’s contractual cash flow characteristics and the Group’s business model for managing them. The Group initially measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs.

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Financial assets designated at FVOCI with no recycling of cumulative gains and losses upon derecognition (equity instruments) Financial assets at FVTPL

The Group has no financial asset classified as financial assets at FVOCI.

 

the financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Financial assets at amortized cost are subsequently measured using the effective interest (EIR) method and are subject to impairment. Gains and losses are recognized in profit or loss when the asset is derecognized, modified or impaired. The Group’s financial assets at amortized cost include cash and cash equivalents, receivables, restricted cash and refundable deposits. Financial assets at FVTPL Financial assets at fair value through profit or loss include financial assets held for trading, financial assets designated upon initial recognition at fair value through profit or loss, or financial assets mandatorily required to be measured at fair value. Financial assets are classified as held for trading if they are acquired for the purpose of selling or repurchasing in the near term. Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated as effective hedging instruments. Financial assets with cash flows that are not solely payments of principal and interest are classified and measured at fair value through profit or loss, irrespective of the business model. Notwithstanding the criteria for debt instruments to be classified at amortized cost or at fair value through OCI, as described above, debt instruments may be designated at fair value through profit or loss on initial recognition if doing so eliminates, or significantly reduces, an accounting mismatch. Financial assets at fair value through profit or loss are carried in the consolidated statement of financial position at fair value with net changes in fair value recognized in the consolidated statement of profit or loss.

In order for a financial asset to be classified and measured at amortized cost or fair value through OCI, it needs to give rise to cash flow that are ‘solely payments of principal and interest (SPPI)’ on the principal amount outstanding. This assessment is referred to as the SPPI test and is performed at an instrument level.

This category includes derivative instruments and listed equity investments which the Group had not irrevocably elected to classify at fair value through OCI. Dividends on listed equity investments are also recognized as other income in the consolidated statement of profit or loss when the right of payment has been established.

The Group’s business model for managing financial assets refers to how it manages its financial assets in order to generate cash flows. The business model determines whether cash flows will result from collecting contractual cash flows, selling the financial assets, or both.

The Group’s financial assets at FVTPL includes marketable equity securities and investment in golf club shares.

Subsequent measurement For purposes of subsequent measurement, financial assets are classified in four categories:  

Financial assets at amortized cost (debt instruments) Financial assets at FVOCI with recycling of cumulative gains and losses (debt instruments)

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Impairment of financial assets The Group recognizes an allowance for ECLs for all debt instruments not held at FVTPL. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms.

When the Group has transferred its rights to receive cash flows from an asset and has neither transferred nor retained substantially all the risks and rewards of the asset nor transferred control of the asset, the asset is recognized to the extent of the Group’s continuing involvement in the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that the Group could be required to repay.

ECLs are recognized in two stages. For credit exposures for which there has not been a significant increase in credit risk since initial recognition, ECLs are provided for credit losses that result from default events that are possible within the next 12-months (a 12-month ECL). For those credit exposures for which there has been a significant increase in credit risk since initial recognition, a loss allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).

Financial liabilities A financial liability is derecognized when the obligation under the liability is discharged, cancelled or has expired.

The Group may consider a financial asset to be in default when internal or external information indicates that the Group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the Group. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial Liabilities - Initial recognition and measurement Financial liabilities are classified, at initial recognition, as financial liabilities at FVTPL, financial liabilities at amortized cost (loans and borrowings) or as derivatives designated as hedging instruments in an effective hedge, as appropriate.

Offsetting of Financial Instruments Financial assets and financial liabilities are set off and the net amount is reported in the consolidated statement of financial position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the asset and settle the liability simultaneously.

All financial liabilities are recognized initially at fair value and, in the case of loans and borrowings and payables, net of directly attributable transaction costs.

Fair Value Measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either:

The Group’s financial liabilities include accounts payable and accrued expenses, excluding statutory liabilities, loans payable and lease liabilities. The Group does not have financial liabilities at FVTPL.

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Subsequent measurement After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortized cost using the EIR method. Gains and losses are recognized in profit or loss when the liabilities are derecognized as well as through the EIR amortization process.

The principal or the most advantageous market must be accessible to by the Group. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.

Amortized cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the EIR. The EIR amortization is included as finance costs in the statement of comprehensive income. Derecognition of Financial Assets and Financial Liabilities Financial assets A financial asset (or where applicable, a part of a financial asset or part of a group of similar financial assets) is derecognized when:   

the rights to receive cash flows from the asset have expired; the Group retains the rights to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third party under a “pass-through” arrangement; or the Group has transferred its right to receive cash flows from the asset and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.

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Where an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognized in profit or loss.

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In the principal market for the asset or liability, or In the absence of a principal market, in the most advantageous market for the asset or liability.

The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorized within the fair value hierarchy, described as follows, based on the lowest level input that is significant to the fair value measurement as a whole:   

Level 1 - Quoted (unadjusted) market prices in active markets for identical assets or liabilities Level 2 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable Level 3 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable

For assets and liabilities that are recognized in the financial statements on a recurring basis, the Group determines whether transfers have occurred between Levels in the hierarchy by re-assessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period.

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Crude Oil Inventory Crude oil inventory is stated at NRV at the time of production. NRV is the estimated selling price less cost to sell. The estimated selling price is the market values of crude oil inventory at the time of production. Other Current Assets This account comprises restricted cash, supplies inventory, prepayments and advances to suppliers. Restricted cash is recognized when the Group reserves a portion of its cash to pay loan interest charges and loan principal amortization and when cash is deposited in an escrow fund. Restricted cash that are expected to be used for a period of no more than 12 months after the financial reporting period are classified as current assets, otherwise, these are classified as noncurrent assets. Supplies inventory refers to parts purchased for used in operations. Supplies inventory are stated at the lower of cost or NRV. Cost is determined using the specific identification method. NRV is the current replacement cost of supplies inventory. Prepayments are expenses paid in advance and recorded as asset before these are utilized. The prepaid expenses are apportioned over the period covered by the payment and charged to the appropriate accounts in profit or loss when incurred. Prepayments that are expected to be realized for a period of no more than 12 months after the financial reporting period are classified as current assets, otherwise, these are classified as noncurrent assets. Advances to suppliers are reclassified to the proper asset or expense account and deducted from the supplier’s billings as specified in the provisions of the contract. Property, Plant and Equipment Property, plant and equipment, except for land, are stated at cost less accumulated depletion, depreciation and amortization and any accumulated impairment losses. Land is stated at cost less any accumulated impairment losses. The initial cost of the property, plant and equipment consists of its purchase price, including any import duties, taxes and any directly attributable costs of bringing the assets to its working condition and location for its intended use and abandonment costs. Expenditures incurred after the fixed assets have been put into operation, such as repairs and maintenance, are normally charged to the consolidated statement of comprehensive income in the period in which the costs are incurred. In situations where it can be clearly demonstrated that the expenditures have resulted in an increase in the future economic benefits expected to be obtained from the use of an item of property, plant and equipment beyond its originally assessed standard of performance, the expenditures are capitalized as an additional cost of property, plant and equipment. Depreciation of an item of property, plant and equipment begins when it becomes available for use, i.e., when it is in the location and condition necessary for it to be capable of operating in the manner intended by management. Depreciation ceases at the earlier of the date that the item is classified as held for sale (or included in a disposal group that is classified as held for sale) in accordance with PFRS 5, Non-current Assets Held for Sale and Discontinued Operations, and the date the asset is derecognized. Wells, platforms and other facilities related to oil operations are depleted using the units-of-production method computed based on estimates of proved reserves. The depletion base includes the exploration and development cost of the producing oilfields.

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Land improvements consist of betterments, site preparation and site improvements that ready land for its intended use. These include excavation, non-infrastructure utility installation, driveways, sidewalks, parking lots, and fences. Property, plant and equipment are depreciated and amortized using the straight-line method over the estimated useful lives of the assets as follows: Power plant, FCRS and production wells Office condominium units Land improvements Transportation equipment Office improvements Office furniture and other equipment

Number of Years 25 15 5 4 3 2 to 3

The useful lives and depletion, depreciation and amortization methods are reviewed periodically to ensure that the period and method of depletion, depreciation and amortization are consistent with the expected pattern of economic benefits from items of property, plant and equipment. Construction in progress represents property, plant and equipment under construction and is stated at cost. This includes the cost of construction to include materials, labor, professional fees, borrowing costs and other directly attributable costs. Construction in progress is not depreciated until such time the construction is completed. Fully depreciated assets are retained in the accounts until they are no longer in use and no further depreciation is credited or charged to current operations. When the assets are retired or otherwise disposed of, the cost and the related accumulated depletion, depreciation and amortization and any accumulated impairment losses are removed from the accounts and any resulting gain or loss is recognized in profit or loss. Borrowing Costs Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period of time to get ready for its intended use or sale are capitalized as part of the cost of the asset. All other borrowing costs are expensed in the period in which they occur. Borrowing costs consist of interest and other costs that an entity incurs in connection with the borrowing of funds. Deferred Oil Exploration Costs PERC follows the full cost method of accounting for exploration costs determined on the basis of each SC area. Under this method, all exploration costs relating to each SC are tentatively deferred pending determination of whether the area contains oil reserves in commercial quantities. Deferred oil and gas exploration costs are assessed at each reporting period for possible indications of impairment. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case or is considered as areas permanently abandoned, the costs are written off through the consolidated statement of comprehensive income. Exploration areas are considered permanently abandoned if the related permits of the exploration have expired and/or there are no definite plans for further exploration and/or development.

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The exploration costs relating to the SC where oil in commercial quantities are discovered are subsequently reclassified to “Wells, platforms and other facilities” shown under “Property and equipment” account in the consolidated statements of financial position upon substantial completion of the development stage. On the other hand, all costs relating to an abandoned SC are written off in the year the area is permanently abandoned. SCs are considered permanently abandoned if the SCs have expired and/or there are no definite plans for further exploration and/or development.

Investment in a Joint Venture (JV) A JV is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Investment in a JV is accounted for under the equity method of accounting.

Deferred Development Costs - Geothermal included in Other Noncurrent Assets All costs incurred in the geological and geophysical activities such as costs of topographical, geological and geophysical studies, rights of access to properties to conduct those studies, salaries and other expenses of geologists, geophysical crews, or others conducting those studies are charged to profit or loss in the year such costs are incurred.

Under the equity method, the investment in a JV is initially recognized at cost. The carrying amount of the investment is adjusted to recognize changes in the Group’s share of net assets of the JV since the acquisition date.

If the results of initial geological and geophysical activities reveal the presence of geothermal resource that will require further exploration and drilling, subsequent exploration and drilling costs are accumulated and deferred under the “Other noncurrent assets” account in the consolidated statement of financial position. These costs include the following:   

costs associated with the construction of temporary facilities; costs of drilling exploratory and exploratory type stratigraphic test wells, pending determination of whether the wells can produce proved reserves; and costs of local administration, finance, general and security services, surface facilities and other local costs in preparing for and supporting the drill activities, etc. incurred during the drilling of exploratory wells.

If tests conducted on the drilled exploratory wells reveal that these wells cannot produce proved reserves, the capitalized costs are charged to expense except when management decides to use the unproductive wells for recycling or waste disposal. Once the project’s technical feasibility and commercial viability to produce proved reserves are established, the exploration and evaluation assets shall be reclassified to “Property, plant and equipment” and depreciated accordingly. Deferred Development Costs - Solar Power Project included in Other Noncurrent Assets These are costs incurred in the development of the solar plant expansion project. Costs are capitalized if the technological and economic feasibility is confirmed, usually when a project development has reached a defined milestone according to an established project management model. These costs include the following:  costs incurred for the expansion of the solar plant project  costs of administration, finance, general and security services and other costs attributed to the expansion of the project. Deferred development costs of the Solar Power Project is recognized under “Other noncurrent assets” in the statement of financial position. Once the project’s technical feasibility and commercial viability has been established, development costs shall be reclassified to “Property, plant and equipment” and depreciated accordingly.

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The consolidated statement of comprehensive income reflects the Group’s share of the financial performance of the joint venture. Any change in OCI of those investees is presented as part of the Group’s OCI. In addition, when there has been a change recognized directly in the equity of the JV, the Group recognizes its share of any changes, when applicable, in the consolidated statement of changes in equity. Unrealized gains and losses from transactions between the Group and the JV are eliminated to the extent of the interest of the JV. The aggregate of the Group’s share in profit or loss of a JV is shown under “Other income (charges)” in the consolidated statement of comprehensive income and represents profit or loss after tax and noncontrolling interests in the subsidiaries of the JV. The financial statements of the JV are prepared in the same reporting period of the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group. After application of the equity method for the investment in a JV, the Group determines whether it is necessary to recognize an impairment loss on its investment in a JV. At each reporting date, the Group determines whether there is objective evidence that the investment in JV is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the JV and its carrying value, then recognizes the loss in the consolidated statement of comprehensive income. Upon loss of joint control over the JV, the Group measures and recognizes any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognized in the consolidated statement of comprehensive income. Contract Assets A contract asset is recognized for the earned consideration for goods or services transferred to a customer before the customer pays or before payment is due. Contract assets are measured at the present value of future collections to be received over a period of time. Contract assets that are expected to be received within 12 months after the financial reporting period are classified as current assets, otherwise, these are classified as noncurrent assets. Intangible Assets Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired is their fair value as at the date of acquisition. Following initial recognition, intangible assets are carried at cost less accumulated amortization and accumulated impairment losses, if any.

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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Intangible assets with finite lives are amortized over their useful economic lives and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization period and the amortization method for an intangible asset with a finite useful life are reviewed at least at the end of each reporting period. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset is accounted for by changing the amortization period or method, as appropriate, and are treated as changes in accounting estimates.

The Group recognized in relation to its interest in a joint operation its:  assets, including its share of any assets held jointly  liabilities, including its share of any liabilities incurred jointly  revenue from the sale of its share of the output arising from the joint operation  share of the revenue from the sale of the output by the joint operation  expenses, including its share of any expenses incurred jointly

The amortization expense on intangible assets with finite lives is recognized in the consolidated statement of comprehensive income in the expense category consistent with the function of the intangible assets.

The Group accounts for the assets it controls and the liabilities it incurs, the expenses it incurs and the share of income that it earns from the sale of crude oil by the joint operations.

Intangible assets are amortized using the straight-line method over the estimated useful lives of the assets as follows: Land rights Production license Software license

Number of Years 25 10 1.5 to 3

Gains or losses arising from derecognition of an intangible asset are measured as the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in the consolidated statement of comprehensive income when the asset is derecognized. Investment Properties Investment properties consist of land held for capital appreciation. Land is stated at cost less any impairment in value. The initial cost of the investment properties comprises its purchase price and any directly attributable costs of bringing the asset to its working condition. Expenditures incurred after the investment properties have been put into operation, such as repairs and maintenance, are normally charged to expense in the year when costs are incurred. In situations where it can be clearly demonstrated that the expenditures have resulted in an increase in the future economic benefits expected to be obtained from the use of an item of investment properties beyond its originally assessed standard of performance, the expenditures are capitalized as an additional cost of investment properties. Investment property is derecognized when either it has been disposed of or when the investment property is permanently withdrawn from use and no future economic benefit is expected from its disposal. Any gains or losses on the retirement or disposal of investment properties are recognized in the consolidated statement of comprehensive income in the year of retirement or disposal.

Impairment of Nonfinancial Assets The Group assesses at each reporting date whether there is an indication that an asset (e.g., property, plant and equipment, investment properties, deferred costs, intangible assets and right-of-use assets) may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group estimates the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or cash-generating unit’s fair value less costs to sell and its value in use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or group of assets. Where the carrying amount of an asset exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded companies or other available fair value indicators. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Group makes an estimate of recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization had no impairment loss been recognized for the asset in prior years.

Interest in Joint Operations A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement.

Capital Stock and Additional Paid-in Capital The Group records common stock at par value and additional paid-in capital in excess of the total contributions received over the aggregate par values of the equity shares. When the Group issues more than one class of stock, a separate account is maintained for each class of stock and the number of shares issued. Incremental costs incurred directly attributable to the issuance of new shares are shown in equity as a deduction from proceeds, net of tax. When any member of the Group purchases the Group’s capital stock (treasury shares), the consideration paid, including any attributable incremental costs, is deducted from equity attributable to the Group’s equity holders until the shares are cancelled, reissued or disposed of. Where such shares are subsequently sold or reissued, any consideration received, net of any directly attributable incremental transaction costs and the related tax effects, is included in equity.

*SGVFSM008891*

Transfers are made to investment properties when, and only when, there is a change in use, evidenced by the end of owner-occupation, commencement of an operating lease to another party or by the end of construction or development. Transfers are made from investment properties when, and only when, there is a change in use, evidenced by commencement of owner-occupation or commencement of development with a view to sell.

The Group’s participating interest in the Etame block in Gabon, West Africa and participating interests in Philippine service contracts (SCs) are classified as joint operations.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

PETROENERGY RESOURCES CORPORATION

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Deposits for Future Stock Subscriptions Deposits for future stock subscriptions is recorded based on the redeemable amounts received and is presented under liabilities unless the following items were met for classification as part of equity: a. the unissued authorized capital stock of the entity is insufficient to cover the amount of shares indicated in the contract; b. there is BOD approval on the proposed increase in authorized capital stock (for which a deposit was received by the Group); c. there is stockholders’ approval of said proposed increase; and d. the application for the approval of the proposed increase has been filed with the Securities and Exchange Commission (SEC). Deposits represent subscription payments received from prospective investors for the Group’s common shares which are yet to be issued upon approval by the SEC of the application for increase in the authorized capital stock. This will be reclassified to ‘Capital stock’ upon issuance of the subscribed shares. Retained Earnings Retained earnings represent the cumulative balance of consolidated net income, effects of changes in accounting policy and other capital adjustments, net of dividend declaration. Unappropriated retained earnings represent the portion which can be declared as dividends to stockholders after considering the undistributed accumulated equity in a subsidiary, funds appropriated for corporate expansion projects or programs, restrictions under loan agreements and funds retained under special circumstances for probable contingencies.

The revenue recognized from the sale of petroleum products pertains to the Group’s share in revenue from the joint operations. The revenue sharing is accounted for in accordance with PFRS 11, Joint Arrangements. Interest income Interest income is recognized as the interest accrues taking into account the effective yield on the asset. Dividend income Dividend income is recognized according to the terms of the contract, or when the right of the payment has been established. Share in Net Income of a Joint Venture Share in net income of a joint venture represents the Group’s share in profit or loss of its joint venture, PWEI. Miscellaneous Income Miscellaneous income is recognized when the Group’s right to receive the payment is established.

Appropriated retained earnings represent the portion which has been restricted and therefore is not available for any dividend declaration.

Costs and Expenses Cost of electricity sales Costs of electricity sales pertain to direct costs in generating electricity power which includes operating and maintenance costs (O&M) for power plant and fluid collection and reinjection system (FCRS), depreciation and other costs directly attributed to producing electricity.

Cumulative Translation Adjustment Cumulative translation adjustment represents the resulting exchange differences in the remeasurement of accounts due to change in functional currency.

Oil production Oil production are costs incurred to produce and deliver crude oil inventory, including transportation, storage and loading, among others.

Equity Reserve Equity reserve is made up of equity transactions other than equity contributions such as gain or loss resulting from increase or decrease of ownership without loss of control.

Change in crude oil inventory Change in crude oil inventory pertains to the movement of beginning and ending crude oil inventory charged as part of cost of sales.

Dividend Distribution Cash dividends on capital stock are recognized as a liability and deducted from retained earnings when approved by the BOD.

General and administrative expenses General and administrative expenses constitute costs of administering the business.

Revenue Recognition Revenue is recognized when the control of petroleum and electricity are transferred to the customer at an amount that reflects the consideration which the Group expects to be entitled in exchange for those goods and services. The Group has generally concluded that it is the principal in its revenue arrangements. Electricity sales Revenues from sale of electricity using renewable energy is consummated and recognized over time whenever the electricity generated by the Group is transmitted through the transmission line designated by the buyer, for a consideration.

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Oil revenues Revenue from crude oil is recognized at a point in time when the control of the goods has transferred from the sellers (Consortium) to the buyer at the delivery point. Revenue is measured at the fair value of the consideration received.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

Costs and expenses are recognized as incurred. Income Taxes Current Tax Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted at the reporting date. Deferred Tax Deferred tax is provided using the balance sheet liability method on all temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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Deferred tax liabilities are recognized for all taxable temporary differences except to the extent that the deferred tax liabilities arise from the: a) initial recognition of goodwill; or b) the initial recognition of an asset or liability in a transaction which is not: i) a business combination; and ii) at the time of the transaction, affects neither accounting profit nor taxable profit or loss. Deferred tax assets are recognized for all deductible temporary differences with certain exceptions, and carryforward benefits of unused tax credits from excess minimum corporate income tax (MCIT) over RCIT and unused net operating loss carryover (NOLCO), to the extent that it is probable that sufficient taxable income will be available against which the deductible temporary differences and carryforward benefits of unused tax credits from excess MCIT and unused NOLCO can be utilized. Deferred tax assets, however, are not recognized when it arises from the: a) initial recognition of an asset or liability in a transaction that is not a business combination; and b) at the time of transaction, affects neither the accounting income nor taxable profit or loss. The carrying amounts of deferred tax assets are reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the deferred tax assets to be utilized. Unrecognized deferred tax assets are reassessed at each reporting date, and are recognized to the extent that it has become probable that future taxable income will allow the deferred tax assets to be recovered. The Group does not recognize deferred tax assets and deferred tax liabilities that will reverse during the income tax holiday (ITH). Deferred tax assets and liabilities are measured at the tax rates that are applicable to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted as of the reporting date. Deferred tax relating to items recognized outside profit or loss is recognized outside profit or loss. Deferred tax items are recognized in correlation to the underlying transaction either in profit or loss or other comprehensive income. Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority. Value-Added Tax (VAT) Revenues, expenses and assets are recognized net of the amount of VAT, if applicable. When VAT from sales of goods or services (output VAT) exceeds VAT passed on from purchases of goods or services (input VAT), the excess is recognized as payable in the consolidated statement of financial position. When VAT passed on from purchases of goods or services (input VAT) exceeds VAT from sales of goods and/or services (output VAT), the excess is recognized as an asset in the consolidated statement of financial position as part of “Other noncurrent assets” to the extent of the recoverable amount. Leases Group as a lessee The Group assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

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Right-of-use assets The Group recognizes right-of-use assets at the commencement date of the lease. Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liability. The cost of right-of-use assets includes the amount of lease liability recognized, and lease payments made at or before the commencement date less any lease incentives received and estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease, unless those costs are incurred to produce inventories. Unless the Group is reasonably certain to obtain ownership of the leased asset at the end of the lease term, the recognized right-of-use assets are depreciated on a straight-line basis over the shorter of its estimated useful life and the lease term, as follows: Office space Land

Number of Years 2 18 to 25

Lease liabilities At the commencement date of the lease, the Group recognizes lease liability measured at the present value of lease payments to be made over the lease term. The lease payments include fixed payments less any lease incentives receivable, variable lease payments that depend on an index or a rate, and amounts expected to be paid under residual value guarantees. The lease payments also include the exercise price of a purchase option reasonably certain to be exercised by the Group and payments of penalties for terminating a lease, if the lease term reflects the Group exercising the option to terminate. The variable lease payments that do not depend on an index or a rate are recognized as expense in the period on which the event or condition that triggers the payment occurs. In calculating the present value of lease payments, the Group uses the incremental borrowing rate at the lease commencement date if the interest rate implicit in the lease is not readily determinable. After the commencement date, the amount of lease liability is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liability is remeasured if there is a modification, a change in the lease term, a change in the in-substance fixed lease payments or a change in the assessment to purchase the underlying asset. Short-term leases and leases of low-value assets The Group applies the short-term lease recognition exemption to its short-term leases (i.e., those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies to the leases of low-value assets recognition exemption to leases that are considered of low value (i.e., below = P250,000). Lease payments on short-term leases and leases of lowvalue assets are recognized as expense on a straight-line basis over the lease term. Accrued Retirement Liability The net defined benefit liability or asset is the aggregate of the present value of the defined benefit obligation at the end of the reporting period reduced by the fair value of plan assets (if any), adjusted for any effect of limiting a net defined benefit asset to the asset ceiling. The asset ceiling is the present value of any economic benefits available in the form of refunds from the plan or reductions in future contributions to the plan. The cost of providing benefits under the defined benefit plans is actuarially determined using the projected unit credit method.

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Defined benefit costs comprise the following:  Service cost  Net interest on the net defined benefit liability or asset  Remeasurements of net defined benefit liability or asset

For closed sites or areas, changes to estimated costs are recognized immediately in the consolidated statement of comprehensive income. If the decrease in liability exceeds the carrying amount of the asset, the excess shall be recognized immediately in profit or loss. For the oil operation, the Group depreciates ARO assets based on units-of-production method.

Service costs which include current service costs, past service costs and gains or losses on non-routine settlements are recognized as expense in the consolidated statement of comprehensive income. Past service costs are recognized when plan amendment or curtailment occurs. These amounts are calculated periodically by independent qualified actuaries. Net interest on the net defined benefit liability or asset is the change during the period in the net defined benefit liability or asset that arises from the passage of time which is determined by applying the discount rate based on government bonds to the net defined benefit liability or asset. Net interest on the net defined benefit liability or asset is recognized as expense or income in the consolidated statement of comprehensive income. Remeasurements comprising actuarial gains and losses, return on plan assets and any change in the effect of the asset ceiling (excluding net interest on defined benefit liability) are recognized immediately in OCI in the period in which they arise. Remeasurements are not reclassified to consolidated statement of comprehensive income in subsequent periods. Plan assets are assets that are held by a long-term employee benefit fund. Plan assets are not available to the creditors of the Group nor can they be paid directly to the Group. Fair value of plan assets is based on market price information. When no market price is available, the fair value of plan assets is estimated by discounting expected future cash flows using a discount rate that reflects both the risk associated with the plan assets and the maturity or expected disposal date of those assets (or, if they have no maturity, the expected period until the settlement of the related obligations). If the fair value of the plan assets is higher than the present value of the defined benefit obligation, the measurement of the resulting defined benefit asset is limited to the present value of economic benefits available in the form of refunds from the plan or reductions in future contributions to the plan. The Group’s right to be reimbursed of some or all of the expenditure required to settle a defined benefit obligation is recognized as a separate asset at fair value when and only when reimbursement is virtually certain. Asset Retirement Obligation (ARO) The Group records present value of estimated costs of legal and constructive obligations required to restore the oilfields and plant sites upon termination of its operations. The nature of these restoration activities includes dismantling and removing structures, rehabilitating settling ponds, dismantling operating facilities, closure of plant and waste sites, and restoration, reclamation and re-vegetation of affected areas. The obligation generally arises when the asset is constructed or the ground or environment at the sites are disturbed. When the liability is initially recognized, the present value of the estimated cost is capitalized as part of the carrying amount of the ARO assets (included under “Property, plant and equipment”) and ARO liability. Liability and capitalized costs included in oil properties is equal to the present value of the Group’s proportionate share in the total decommissioning costs of the consortium on initial recognition. Additional costs or changes in decommissioning costs are recognized as additions or charges to the corresponding assets and ARO when they occur.

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SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

For the renewable energy, the Group depreciates ARO assets on a straight-line basis over the estimated useful life of the related asset or the service contract term, whichever is shorter, or written off as a result of impairment of the related asset. The Group regularly assesses the provision for ARO and adjusts the related liability and asset. Foreign Currency-Denominated Transactions and Translation The consolidated financial statements are presented in PHP, which is the Parent Company’s functional and presentation currency. Transactions in foreign currencies are initially recorded in the functional currency using the exchange rate at date of transaction. Monetary assets and liabilities denominated in foreign currencies are reinstated to the functional currency using the closing exchange rate at reporting date. All exchange differences are taken to the consolidated statement of comprehensive income. Nonmonetary items that are measured in terms of historical cost in foreign currency are translated using the exchange rates as at the dates of initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. Earnings Per Share Basic earnings per share is computed on the basis of the weighted average number of shares outstanding during the year after giving retroactive effect to any stock split or stock dividends declared and stock rights exercised during the current year, if any. Diluted earnings per share is computed on the basis of the weighted average number of shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the conversion of all the dilutive potential ordinary shares into ordinary shares. Segment Reporting The Group’s operating businesses are organized and managed separately according to the nature of the products and services provided, with each segment representing a strategic business unit that offers different products and services, serves different markets subject to different risks and returns. Financial information on business segments is presented in Note 27 to the consolidated financial statements. Provisions and Contingencies Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as an interest expense. Provisions are reviewed at each reporting date and adjusted to reflect the current best estimate.

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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Contingent liabilities are not recognized in the financial statements. They are disclosed unless the possibility of an outflow of resources embodying economic benefits is remote. Contingent assets are not recognized in the financial statements but are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed continually to ensure that developments are appropriately reflected in the financial statements. If it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are recognized in the consolidated financial statements. Events After the Reporting Period Post year-end events that provide additional information about the Group’s situation at the reporting date (adjusting events) are reflected in the financial statements, if any. Post year-end events that are not adjusting events are disclosed in the notes to consolidated financial statements when material.

This assessment often requires significant judgment. A different conclusion about both joint control and whether the arrangement is a joint operation or a joint venture, may materially impact the accounting of the investment.

5. Significant Accounting Judgments, Estimates and Assumptions The preparation of the consolidated financial statements in compliance with PFRS requires the Group to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, income and expenses and disclosure of contingent assets and contingent liabilities. Future events may occur which will cause the assumptions used in arriving at the estimates to change. The effects of any change in judgments, estimates and assumptions are reflected in the consolidated financial statements, as they become reasonably determinable.

The Group’s investment in PetroWind is structured in a separate incorporated entity. The Group and the parties to the agreement only have the right to the net assets of the joint venture through the terms of the contractual arrangement. Accordingly, the joint arrangement is classified as a joint venture. As of December 31, 2020 and 2019, the Group’s investment in a joint venture amounted to P =1.64 billion and P =1.56 billion, respectively (see Note 12).

Judgments, estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

The Group and the parties to the agreement in investment in Gabon, West Africa and investments in petroleum concessions in the Philippines have joint control over its rights to the assets and obligations for the liabilities, relating to the arrangement. Accordingly, the joint arrangements are classified as joint operations (see Notes 10 and 11).

Judgments In the process of applying the Group’s accounting policies, management has made the following judgments, apart from those involving estimations, which has the most significant effect on the amounts recognized in the consolidated financial statements:

Estimates and Assumptions The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

Determination of Functional Currency The Parent Company determines its functional currency based on economic substance of underlying circumstances relevant to the Parent Company. The functional currency has been determined to be the PHP based on the economic substance of the Parent Company’s business circumstances.

Estimation of Geothermal Field Reserves The Group performed volumetric reserve estimation to determine the reserves of the Maibarara geothermal field. As a requirement for project financing, The Group engaged at its own cost the New Zealand firm Sinclair Knight Merz (SKM) in 2011 to undertake a comprehensive third-party technical review of the Maibarara geothermal field. This review included analysis of the resource assessment performed in-house by the Group as well as a separate SKM reserve estimation and numerical modeling of the Maibarara reserves.

Capitalization of Deferred Oil Exploration Costs and Deferred Development Costs Initial capitalization of costs is based on management’s judgment that technological and economic feasibility is confirmed, usually when a product development project has reached a defined milestone according to an established project management model. If the accounting policy on capitalization of development costs are not met, such costs are expensed. As of December 31, 2020 and 2019, the carrying value of deferred oil explorations costs amounted to =210.53 million and P P =192.96 million, respectively (see Note 11), and the Group’s deferred development costs amounted to = P3.86 million and P =6.61 million as of December 31, 2020 and 2019, respectively (see Note 15).

*SGVFSM008891* 66

Classification of Joint Arrangements Judgment is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. The Group assesses their rights and obligations arising from the arrangement and specifically considers:  the structure of the joint arrangement - whether it is structured through a separate vehicle  when the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from:  the legal form of the separate vehicle  the terms of the contractual arrangement  other facts and circumstances, considered on a case by case basis

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

The Group’s simulation indicated a mean (P50) proven reserves of 27.8 MW for 25 years. In contrast, SKM calculated the P50 reserves at 44 MW. At 90% probability (P90), the reserves calculated are 28 MW and 12 MW by SKM and the Group, respectively. SKM concluded that the approach taken by the Group is conservative as it limits reservoir thickness to depths where a maximum thickness of 280°C will be encountered although the measured temperature reached as high as 324°C. There is reasonable confidence that the 20 MW (gross) plant development is feasible as the P90 level appears also conservative as with the Group’s approach. In addition, SKM identified indicated reserves, translating to 10 MW-26 MW in the area south of and outside the current area of development.

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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Also, there is a likely geothermal potential south of the proven area where two old wells were drilled and encountered high fluid temperatures (T ~ 300°C). MGI identified the southern block as a probable reserve area. SKM in 2011 suggested that the southern block can be classified as Indicated Resource based on the Australian Code as high temperatures have been intersected by the two wells. SKM estimated that the stored heat in the Southern Block has a resource potential equivalent to 12 MW for a project life of 25 years. An updated reserves estimation using the stored-heat calculation was made in 2015 by the Group as a result of reservoir and production performance and the 2014 drilling campaign. The 2014 drilling proved that the current resource area can produce around 33.1 MW, more than enough to meet the steam requirement of the existing 20 MW power plant plus the 12 MW expansion power plant. Using Monte Carlo simulation to estimate the reserves, the proven resource area has an 80% probability of delivering between 18.1 MW to 50.9 MW over a 25-year operating period. This Monte Carlo simulation also showed that the expected mean reserve for the proven resource area is 30.4 MW for 25 years. The Group engaged a U.S. firm Geothermal Science, Inc. (GSI) in 2015 to perform a third-party technical appraisal of the resource for the planned 12 MW expansion. This third-party review was also made as a requirement for the project financing of MGPP-2 or M2. GSI adopted the technique from the US Geological Survey Circular 790 in making the probabilistic calculation of the geothermal reserves at Maibarara. Based on this approach, GSI estimates that Maibarara has a minimum or proven reserves of 40.2 MW, P90 for 25 years plant life and Most Likely Reserve of 61.6 MW, P50 for 25 years of plant life. The Group commenced producing power commercially last February 8, 2014. To date, the current production wells of M1 and M2 are capable of producing 33.1 MW. These production wells including the complement reinjection wells are concentrated on the proven resource area. As of December 31, 2020 and 2019, there has been no significant change in the estimated reserves that would affect the carrying value and useful life of the Group’s property, plant and equipment.

Estimation of Useful Lives of Property, Plant and Equipment The Group reviews on an annual basis the estimated useful lives of property, plant and equipment based on expected asset utilization as anchored on business plans and strategies that also consider expected future technological developments and market behavior. It is possible that future results of operations could be materially affected by changes in these estimates brought about by changes in the factors mentioned. A reduction in the estimated useful lives of property, plant and equipment would increase the recorded depletion, depreciation and amortization expense and decrease noncurrent assets. There is no change in the estimated useful lives of property, plant and equipment as of December 31, 2020 and 2019. As of December 31, 2020 and 2019, the Group’s depreciable property, plant and equipment amounted to P =7.38 billion and = P7.73 billion, respectively (see Note 10). Impairment of Nonfinancial Assets The Group assesses at each reporting date, whether there is an indication that an asset may be impaired. If any indication exists, or when annual impairment testing for an asset is required, the Group estimates the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or cashgenerating unit’s (CGU) fair value less cost of disposal and its value in use. The recoverable amount is the higher of an asset’s or cash-generating unit’s (CGU) fair value less cost of disposal and its value in use. The fair value less cost of disposal is the amount obtainable from the sale of an asset in an arm’s length transaction while value in use is the present value of estimated future cash flows expected to arise from the continuing use of an asset or CGU and from its disposal at the end of its useful life.

Estimation of Proved and Probable Oil Reserves The Parent Company assesses its estimate of proved and probable reserves on an annual basis. The estimate is based on the technical assumptions and is calculated in accordance with accepted volumetric methods, specifically the probabilistic method of estimation. Probabilistic method uses known geological, engineering and economic data to generate a range of estimates and their associated probabilities.

In determining the present value of estimated future cash flows expected to be generated from the continued use of an asset or CGU, the Group is required to make estimates and assumptions that can materially affect the consolidated financial statements.

All proved and probable reserve estimates are subject to revision, either upward or downward, based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans. Estimates of reserves for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and depleted. Estimated oil reserves are utilized in the impairment testing and the calculation of depletion expense using the unit of production method of the investments in Gabon, West Africa.



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As of December 31, 2020 and 2019, the carrying value of “Wells, Platforms and other Facilities” under “Property, Plant and Equipment” amounted to P =557.77 million and P =577.41 million, respectively (see Note 10).

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

Facts and circumstances that would require an impairment assessment as set forth in PFRS 6, Exploration for and Evaluation of Mineral Resources, are as follows:

  

the period for which the Group has the right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed; substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the entity has decided to discontinue such activities in the specific area; and sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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The related balances of the Group’s nonfinancial assets as of December 31 follow: Property, plant and equipment (Note 10) Right-of-use assets (Note 13) Deferred oil exploration costs (Note 11) Intangible assets (Note 15) Deferred development costs (Note 15) Investment properties (Note 14)

2020 P =8,310,613,046 383,032,125 210,533,496 165,976,162 3,855,596 1,611,533 P =9,075,621,958

2019 =8,536,605,048 P 403,394,701 192,958,190 181,192,511 6,605,102 1,611,533 =9,322,367,085 P

There are no indicators of impairment that would trigger impairment review in 2020 and 2019 other than those mentioned below. Gabon, West Africa The Group believes that the low crude oil prices in the market, political risks in Gabon, discount rates and changes in other assumptions such as change in production profile which is based on continued production until the term of the existing Production Sharing Contract are indicators that the assets might be impaired and thus, prompted the Group to perform impairment testing of the assets. In 2018, the Gabonese Government allowed the sixth amendment to the Exploration Production Sharing Contract (EPSC) that extends the exploitation period for the production licenses by ten (10) years, or from September 2018 until September 2028, extendible by five (5) years and by a final extension of 5 more years. The extension of the EPSC will allow the consortium to maximize the use of the existing facilities that are already in place to increase or maintain production until the field’s extended life (see Note 10). In assessing whether the asset is impaired or if reversal of prior impairment loss is required, the carrying value of the asset is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell and value in use. Given the nature of the Group’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers or similar transactions are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment loss is value in use. The Group estimates value in use using a discounted cash flow model using a discount rate of 10.00% in 2020 and 2019. In 2018, the Group recognized an impairment loss (reversal of impairment loss) amounting to (P =75.97 million) and P =21.65 million for “Wells, platforms and other facilities” and “Deferred oil exploration costs”, respectively (nil in 2019 and 2020). As of December 31, 2020 and 2019, the net carrying value of the assets forming part of the CGU in Gabon, West Africa are as follows: Wells, platforms and other facilities (Note 10) Production license (Note 15) Deferred oil exploration costs (Note 11)

2020 P =557,767,960 35,828,192 24,471,370 P =618,067,522

2019 =577,405,460 P 40,451,185 8,015,333 =625,871,978 P

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Estimating the incremental borrowing rate The Group cannot readily determine the interest rate implicit in the lease, therefore, it uses its incremental borrowing rate (IBR) to measure lease liabilities. The IBR is the rate of interest that the Group would have to pay to borrow over a similar term, and with a similar security, the funds necessary to obtain an asset of a similar value to the right-of-use asset in a similar economic environment. The IBR therefore reflects what the Group ‘would have to pay’, which requires estimation when no observable rates are available or when they need to be adjusted to reflect the terms and conditions of the lease. The Group estimates the IBR by reference to the PH BVAL rate, adjusted by the credit spread of the Group based on current loan agreements. The Group’s lease liabilities amounted to P =335.45 million and P =337.83 million as of December 31, 2020 and 2019, respectively. (see Note 13) Estimation of Asset Retirement Obligations The Group has various legal obligation to decommission or dismantle its assets related to the oil production, geothermal energy project and solar power project at the end of each respective service contract. In determining the amount of provisions for restoration costs, assumptions and estimates are required in relation to the expected costs to restore sites and infrastructure when such obligation exists. The Group recognizes the present value of the obligation to dismantle and capitalizes the present value of this cost as part of the balance of the related property, plant and equipment, which are being depreciated and amortized on a straight-line basis over the useful life of the related assets (for the renewable energy) and based on units-of-production method based on estimates of proved reserves (for the oil operations). Cost estimates expressed at current price levels at the date of the estimate are discounted using a rate ranging from 2.84% to 3.92% in 2020 and 4.39% to 5.17% in 2019 to take into account the timing of payments. Each year, the provision is increased to reflect the accretion of discount and to accrue an estimate for the effects of inflation, with charges being recognized as accretion expense (see Note 18). Changes in the asset retirement obligation that result from a change in the current best estimate of cash flow required to settle the obligation or a change in the discount rate are added to (or deducted from) the amount recognized as the related asset and the periodic unwinding of the discount on the liability is recognized in profit or loss as it occurs. While the Group has made its best estimate in establishing the asset retirement obligation, because of potential changes in technology as well as safety and environmental requirements, plus the actual time scale to complete decommissioning activities, the ultimate provision requirements could either increase or decrease significantly from the Group’s current estimates. The amounts and timing of recorded expenses for any period would be affected by changes in these factors and circumstances. Asset retirement obligation as of December 31 follows (see Note 18): PetroEnergy - Oil production MGI - Geothermal energy project PetroSolar - Solar power project

2020 P =64,070,738 31,209,163 13,879,778 P =109,159,679

2019 =55,571,203 P 24,562,064 10,487,754 =90,621,021 P

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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Recoverability of input VAT The Group maintains an allowance for input VAT based on an assessment of the recoverability of these assets using the historical success rate of VAT refunded from the Bureau of Internal Revenue (BIR). A review is made by the Group on a continuing basis annually to determine the adequacy of the allowance for losses. Allowance for probable losses as of December 31, 2020 and 2019 amounted to = P 6.63 million and P =1.66 million, respectively. The carrying value of input VAT amounted to =206.86 million and = P P220.68 million as of December 31, 2020 and 2019, respectively (see Note 15). Recognition of deferred tax assets The Group reviews the carrying amounts of deferred tax assets at each reporting date and reduces them to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax assets to be utilized. As of December 31, 2020 and 2019, the Group did not recognize deferred tax assets on certain NOLCO and MCIT as the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future against which the tax benefits can be realized prior to their expiration. As of December 31, 2020 and 2019, gross deferred tax assets recognized amounted to =27.80 million and = P P23.39 million, respectively (see Note 20).

2020 P =607,252,608 660,079,436 P =1,267,332,044

2019 =625,028,938 P 441,669,139 =1,066,698,077 P

Cash in banks earn interest at the prevailing bank deposit rates. Cash equivalents are made for varying periods of up to three months depending on the immediate cash requirements of the Group and earn interest at the prevailing short-term deposit rates. Interest income earned on cash and cash equivalents and restricted cash (see Note 9) amounted to =18.03 million, P P =43.92 million and = P34.79 million in 2020, 2019 and 2018, respectively.

7. Receivables Accounts receivable from: Electricity sales and other charges to ACEN (formerly PHINMA) [Note 25] Feed-in-Tariff (FiT) revenue from National Transmission Corporation (TransCo) Consortium operator PHESCO, Incorporated (PHESCO) Electricity sales to Wholesale Electricity Spot Market (WESM) Affiliate (Note 25) Others

2020

2019

P =116,391,600

=104,098,660 P

96,878,750 32,808,612 15,245,231

94,025,965 73,339,544 12,263,904

7,641,677 1,933,908 1,932,374

19,534,580 2,230,515 761,992

(Forward)

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Less allowance for impairment losses

2019 =1,348,378 P 27,968,537 335,572,075 2,682,452 =332,889,623 P

Receivables are generally on 30 days credit term. Interest income earned from the delayed payment of FiT differential amounted to = P8.98 million in 2018 (nil in 2019 and 2020). Other receivables in 2019 pertain to the amount due from Rizal Commercial Banking Corporation (RCBC) for withholding tax on interest expense for the Project Loan Facility Agreement advanced by the Group (see Note 17). This amount was subsequently collected in 2020. 8. Financial Assets at Fair Value Through Profit or Loss Marketable equity securities Investment in golf club shares

6. Cash and Cash Equivalents Cash on hand and in banks Cash equivalents

Interest receivables Other receivables

2020 P =895,945 2,526,250 276,254,347 2,682,452 P =273,571,895

2020 P =6,761,587 770,000 P =7,531,587

2019 =7,470,096 P 770,000 =8,240,096 P

Net loss on fair value changes on financial assets at FVTPL included in the consolidated statements of comprehensive income amounted to = P0.71 million, = P0.24 million and = P0.58 million in 2020, 2019 and 2018, respectively. Dividend income received from equity securities amounted to = P0.07 million, =0.06 million and = P P0.08 million in 2020, 2019 and 2018, respectively (see Note 24). 9. Other Current Assets Restricted cash Supplies inventory Prepaid expenses Prepaid taxes Advances to suppliers Others

2020 P =549,011,453 106,005,350 17,283,912 15,116,146 7,725,445 1,880,404 P =697,022,710

2019 =595,874,394 P 83,227,307 28,199,797 12,863,669 4,051,107 3,689,963 =727,906,237 P

Restricted Cash Restricted cash includes the amount of fund that the Group is required to maintain in the Debt Service Payment Account (DSPA) and Debt Service Reserve Account (DSRA) pursuant to the Omnibus Loan and Security Agreement (OLSA) of MGI and PetroSolar, respectively (see Note 16). Restricted cash also includes the remaining unused portion of the Stock Rights Offering Proceeds held under an escrow account amounting to ₱154.12 million and ₱152.03 million as of December 31, 2020 and 2019, respectively. Supplies Inventory Supplies inventory refers to purchased supplies and parts that are intended to be used for operations and maintenance.

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

*SGVFSM008891*

74 SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT = P1,562,738,120 – – 5,444,510 – 425,295 1,568,607,925 260,867,044 69,553,776 – 330,420,820 – = P1,238,187,105

= P7,211,984,013 12,119,628 – 2,848,844 – 11,965,624 7,238,918,109 1,101,299,995 305,456,658 – 1,406,756,653 – = P 5,832,161,456

1,223,735,862 82,236,533 – 1,305,972,395 158,657,126 = P764,088,685

9,155,462 – – 2,228,718,206

34,267,669

= P2,166,119,173 19,175,902

26,485,766 5,425,175 – 31,910,941 – = P264,739,267

– – – 296,650,208

–

= P293,346,620 3,303,588

40,769,200 70,501 – 40,839,701 – = P735,168

– – – 41,574,869

–

= P40,991,861 583,008

36,100,378 6,247,975 (2,817,784) 39,530,569 – = P10,508,277

– (2,920,998) – 50,038,846

–

= P51,082,742 1,877,102

Transportation equipment

104,251,114 19,292,570 – 123,543,684 – = P36,618,322

– – – 160,162,006

–

= P144,493,150 15,668,856

Office furniture and other equipment

2,793,509,359 488,283,188 (2,817,784) 3,278,974,763 158,657,126 = P8,310,613,046

17,448,816 (2,920,998) – 11,748,244,935

34,267,669

= P11,488,771,533 210,677,915

Total

*SGVFSM008891*

– – – – – = P163,574,766

– – (12,390,919) 163,574,766

–

= P18,015,854 157,949,831

Construction in progress

Advances to Suppliers Advances to suppliers pertain to down payments to various suppliers for the purchase of materials and services for the current operations.

Power plants

Land and land improvements

Prepaid Taxes Prepaid taxes pertain to creditable withholding taxes and prior year’s income tax credit.

Cost Balances at beginning of year Additions Transfers from deferred oil exploration costs (Note 11) Change in ARO estimate (Note 18) Disposal Reclassifications Balances at end of year Accumulated depletion and depreciation Balances at beginning of year Depletion and depreciation Disposals Balances at end of year Accumulated impairment losses Net book values

Wells, platforms and other facilities

2020 Office condominium units and improvements

Prepaid Expenses Prepaid expenses include various prepaid insurances, services and rent. Prepaid expenses also include advance payment for Real Property Taxes (RPT), Stand-by Letter of Credit (SBLC) charges and operations and maintenance professional fees.

FCRS and production wells - geothermal

10. Property, Plant and Equipment

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PETROENERGY RESOURCES CORPORATION

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891*

2,350,753,059 443,552,959 (796,659) 2,793,509,359 158,657,126 =8,536,605,048 P – – – – – =18,015,854 P 87,305,444 16,947,329 (1,659) 104,251,114 – =40,242,036 P 28,934,921 7,960,457 (795,000) 36,100,378 – =14,982,364 P 40,725,745 43,455 – 40,769,200 – =222,661 P 20,993,615 5,492,151 – 26,485,766 – =266,860,854 P 192,997,406 67,869,638 – 260,867,044 – =1,301,871,076 P 811,905,265 289,394,730 – 1,101,299,995 – =6,110,684,018 P

1,167,890,663 55,845,199 – 1,223,735,862 158,657,126 =783,726,185 P

51,082,742

24,609,005 (2,491,104) – 11,488,771,533 – – (725,615,920) 18,015,854 – (32,000) 1,387,559 144,493,150 – (2,459,104)

– – – 40,991,861 – – 8,303,764 293,346,620 7,234,343 – 3,600,181 1,562,738,120 5,505,476 – 712,324,416 7,211,984,013

11,869,186 – – 2,166,119,173

11,901,978 – – –

11,901,978

–

58,552,000 432,934 – – 58,119,066

–

= P10,446,834,797 949,364,857 = P41,763,095 701,435,745 = P128,876,866 14,260,725 = P47,432,450 6,109,396 = P40,991,861 – = P99,800,307 185,242,549 = P1,549,575,653 2,327,943 = P6,429,701,275 6,333,780

Cost Balances at beginning of year Additions Transfers from deferred development costs (Note 15) Transfers from deferred oil exploration costs (Note 11) Change in ARO estimate (Note 18) Disposal Reclassifications Balances at end of year Accumulated depletion and depreciation Balances at beginning of year Depletion and depreciation Disposals Balances at end of year Accumulated impairment losses Net book values

Power plants

= P2,108,693,290 33,654,719

Land and land improvements FCRS and production wells - geothermal

Wells, platforms and other facilities

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2019 Office condominium units and improvements

Transportation equipment

Total Construction in progress Office furniture and other equipment

- 35 Power plants represent MGI’s geothermal power plant and PetroSolar’s photovoltaic plant. The Group’s construction in progress account as of December 31, 2020 includes mobilization of Drilling Rig for Workover of one (1) unit Well MB-12D Wellhead Replacement of MGPP, civil structural, piping and mechanical works for M2, interconnection of MGPP to NGCP 69kV distribution line, design, facilities study and construction of 70/77 MVA MGI Substation related to MGPP-1&2 expected to be completed in 2021. Change in ARO estimate and transfers from advances to contractors, deferred oil exploration costs and development costs are considered as noncash investing activities. Depletion and depreciation expense charged to profit or loss follow: Cost of electricity sales (Note 21) Depletion General and administrative expenses (Note 23)

2020 P =394,231,789 82,236,533

2019 =377,738,239 P 55,845,199

2018 =331,552,793 P 81,096,112

11,814,866 P =488,283,188

9,969,521 =443,552,959 P

8,669,441 =421,318,346 P

Depletion of wells, platforms and other facilities is presented as a separate item under cost of sales in the consolidated statements of comprehensive income. As of December 31, 2020 and 2019, the participating interest of PERC in various service contracts areas are as follows: Gabonese Oil Concessions SC 14-C2 – West Linapacan

2.525% 4.137%

Foreign Operations Gabon, West Africa Background The Group holds approximately 2.53% participating interest in the EPSC covering the Etame block in Gabon, West Africa (the “Etame Marin Permit”). The EPSC is a contract with the Gabonese Government that gives the holder of the said EPSC exclusive rights and obligations to perform exploration, exploitation, and production activities within the Etame Marin Permit area. The other parties and their respective participating interests in the EPSC are as follows: Addax Petroleum Etame, Inc. (33.90%); Sasol Petroleum West Africa Limited (30.00%); VAALCO Gabon (Etame), Inc. (33.58%) (the “Gabon Consortium”), all are leaders in their respective areas of operation. VAALCO is the Consortium’s operator, and as such, has the exclusive charge of conducting the exploration and production activities in the Gabon contract area. The Etame Marin Permit consists of an offshore exploration area of 307,360 hectares that extends from depths of 200 meters in the Atlantic shelf to near-shore Gabon. The Gabon Consortium was able to develop four (4) oil fields, namely, Etame, Avouma, Tchibala, and Ebouri oil fields. Aside from the EPSC, other licenses were required for the Gabon Consortium to conduct exploration, production and exploitation in these areas within the EPSC such as the Etame Exclusive Exploitation Authorization (G5-88), the Avouma Exclusive Exploitation Authorization (G5-95), and the Ebouri Exclusive Exploitation Authorization (G5-98) (collectively, the “Production Licenses”). Meanwhile, exploration

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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activities outside of the Production License areas are authorized through the Etame Exploration License (G4-160). In September 2018, the Gabonese Government allowed the Sixth Amendment to the EPSC that extends the exploitation period for the Production Licenses by ten (10) years, or from September 2018 until September 2028, extendible by five (5) years, and by a final extension of five (5) more years. The extension further allows the Consortium to continue to develop the four (4) oil fields in the Etame Marin block offshore in the Republic of Gabon and explore the potential for resources in the surrounding area. The Amendment commits the Consortium to undertake new drillings and technical studies to be completed within two (2) years from the effectivity of the Amendment. Given past production from the block, it is anticipated that the committed drilling program for two (2) development wells and two (2) appraisal wells would further enhance the block’s long-term commercial value. As part of the commitment to the Sixth Amendment to extend the economic life of the field, the Consortium completed a three-well drilling program in the Etame and Southeast Etame fields, using the Topaz Driller jack-up rig. The first well in the drilling program, Etame-9H, was put on-line in November 27, 2019. Subsequent wells, Etame-11H and Southeast Etame-4H, were put on-line on January 4, 2020 and on March 22, 2020, respectively. Two (2) old wells, Etame-10H and Southeast Etame-2H, were also worked-over. Upon completion of the three-well drilling and two-well workover program in February 2020, overall crude production rose from just ~11,000 barrels of oil per day (BOPD) in October 2019 to ~22,000 BOPD – last experienced in mid-2009 after the Ebouri Field was put on-line. In July 2020, the Gabonese government imposed a production curtailment to the Etame Marin block to comply with OPEC-mandated supply cuts as a result of global supply-demand imbalance brought about by COVID-19-related business and operational restrictions starting March 2020. Overall crude production was reduced to ~14,000 - 16,000 BOPD up to March 2021. In November 2020, the consortium completed a 1,000 sq.km 3D seismic survey over the Etame Marin block using the Polarcus Adira seismic vessel, which aims to explore other drilling targets within the existing fields, as well as other near-field structures which can be programmed in the succeeding drilling campaigns, which will start in late-2021 to 2022. Given the extended EPSC period, the Consortium is currently firming up the most feasible Integrated Field Development Plan (IFDP) to extract the remaining recoverable oil volumes until at least 2028 up to 2038 (final extension). This IFDP may include: 1) production from sour oil reserves, 2) outfield drilling opportunities, and 3) facility maintenance strategies. In November 2020, the consortium completed a 1,000 sq.km 3D seismic survey over the Etame Marin block using the Polarcus Adira seismic vessel, which aims to explore other drilling targets within the existing fields, as well as other near-field structures which can be programmed in the succeeding drilling campaigns, which will start in late-2021 to 2022. Update on Production Production is routed to the Petroleo Nautipa, the spread-moored Floating Production Storage and Offloading (FPSO) vessel from the Etame, Avouma-Southeast Etame-North Tchibala and Ebouri platforms, and from the wells tied to the subsea Etame manifold. The produced oils are processed and exported from the FPSO, which has a storage capacity of one million barrels of oil (MMBO).

In 2020, total crude production reached 6.57 MMBO. The Consortium managed 11 liftings, resulting in a net crude export of 6.02 MMBO, with crude oil market prices ranging from US$17 - US$66 per barrel. In 2019, total crude production reached 4.70 MMBO. The Consortium managed 14 liftings, resulting in a net crude export of 4.63 MMBO, with crude oil market prices ranging from US$59 - US$71 per barrel. In 2018, total crude production reached 5.06 MMBO. The Consortium managed 14 liftings, resulting in a net crude export of 5.34 MMBO, with crude oil market prices ranging from US$55-US$80 per barrel. Since the Gabon oilfield has been put on-line in 2002, a total of 119 MMBO has been extracted to date over the last 18 years. Philippine Operations SC. No. 14 - C2 (West Linapacan) - North West Palawan West Linapacan was discovered in the early 1990s. It produced oil from 1992 to 1996, peaking at 18,000 BOPD, before it was shut-in due to early water incursion. A 1,083 km 3D seismic survey was conducted and processed in 1997 to 1998, however, the farminees opted not to drill a well. The block was in suspension mode until 2006. From 2007 to 2015, two new farminees joined the SC 14-C2 Consortium and committed to conduct Geological and Geophysical (G&G) studies and to drill one (1) well. However, the farminees defaulted and eventually left the Consortium. Philodrill took over as Operator and has been conducting G&G studies to further strengthen the West Linapacan block to be revived for production. In July 2018, CWT Consultancy Ltd. was engaged for a three-month scoping study to investigate the feasibility of a re-entry of the West Linapacan A-1 (WLA-1) to gather reservoir data that would support a subsequent drill-stem test (DST) and/or an extended well test (EWT). Concurrent with the scoping study on the potential WLA-1 re-entry, technical evaluation work focusing on the adjacent West Linapacan “B” (WLB) structure was undertaken, using the 2014 Pre-SDM reprocessed seismic volume acquired from DownUnder Geosolutions (DUG) in early 2017. In 2019, Philodrill advanced the G&G works using recent reprocessed 3D seismic data acquired in 2017. These aimed to mature the field further to identify drilling prospects. Further, the SC 14-C2 Consortium negotiated with a potential farmee for the drilling of these potential drilling targets, in exchange for a majority share and Operatorship of SC 14-C2. This farm-in is subject to the approval of the Department of Energy (DOE). While the Consortium awaited the farmee’s completion of the farm-in documentation, Philodrill continued to do in-house G&G work over at the West Linapacan area at the interim. For compliance, a “Transition Work Program and Budget, covering November 2020 to March 2021 was submitted to the DOE in November 2020 and was approved. SC 14-C2 has not yet expired and was granted with a 15-year extension of the SC as approved by the Department of Energy (DOE) from December 18, 2010 to December 18, 2025.

Crude production comes from four (4) oil fields (Etame, Avouma, Ebouri and North Tchibala).

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*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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As of December 31, 2020 and 2019, PetroEnergy has investments in the West Linapacan Oilfield included in “Wells, platforms and other facilities” account under “Property, plant and equipment” and “Deferred oil exploration costs” amounting to P =206.32 million and P =0.27 million (see Note 11), respectively.

Major power plant components from Fuji Electric Co. Ltd. (“Fuji”, the same supplier as the MGPP-1) were delivered and installed on site from March to April 2017. MGPP-2 was first synchronized to the grid on March 9, 2018, with the full 12 MW attained on March 18, 2018. Reliability tests were then conducted from March 18 to 27, 2018, during which the power plant was on full 12 MW operation.

PetroEnergy holds a 4.137% participating interest in SC 14-C2.

The Energy Regulatory Commission (ERC) formally notified MGI of the approval of MGPP-2’s Certificate of Compliance (COC) application on April 26, 2018. Subsequently, the MGPP-2 was accepted into the Wholesale Electricity Spot Market (WESM) on April 30, 2018 - pegging the MGPP2’s start of Commercial Operations on the same date. This operationally started the application of MGPP-2’s Electricity Supply Agreement (ESA) with PHINMA, now ACEN, wherein all of MGPP-2’s generated electricity are sold to ACEN.

Geothermal Energy Geothermal Renewable Energy Service Contract (GRESC) No. 2010-02-012 Following the DOE’s Philippine Energy Contracting Round for Geothermal in 2009, PetroEnergy signed the Service Contract for the Maibarara Geothermal Power Project (MGPP) on February 1, 2010. PetroEnergy then conducted pre-development activities in 2010 to 2011. In order to carry out the development and operations of the MGPP, PetroEnergy (through its subsidiary, PetroGreen) then created Maibarara Geothermal, Inc. (MGI) along with Trans-Asia Oil and Energy Development Corporation (“Trans-Asia”, subsequently renamed as PHINMA Energy Corporation or “PHINMA”, and now known as AC Energy Corporation or “ACEN”) and PNOC Renewable Corporation (PNOC RC), with 65%, 25%, and 10% equity ownerships, respectively. In June 2019, ACEN, the energy platform of Ayala Corporation, completed the acquisition of PHINMA, including PHINMA’s 25% share in MGI. 20 MW Maibarara-1 Geothermal Power Plant (MGPP-1) The DOE confirmed the commerciality of the 20-MW MGPP-1 in 2011, allowing MGI to proceed with the MGPP’s development stage, involving 1) the drilling of two (2) wells to complete the steam production and reinjection well capacities, and 2) the construction of the steamfield and power plant facilities. The MGPP-1’s 115kV Transmission Line system was successfully connected to the existing Manila Electric Company (MERALCO) line in September 2013. Upon completion of the reliability and performance testing, the MGPP-1 went on commercial operations on February 8, 2014. All electricity generated are sold to offtaker, ACEN, following the aforementioned acquisition of PHINMA by ACEN. On April 26 to 29, 2019, the MGPP-1 had a scheduled minor maintenance shutdown. Various maintenance activities for the unit’s mechanical and electrical and instrumentation facilities, as well as for the switchyard and transmission lines, were carried-out by MGI technical staff and private contractors.

MGPP-2 exported 93.97 GWh and 94.44 GWh of electricity in 2020 and 2019, respectively. Both the MGPP-1 and the MGPP-2 are registered with the Board of Investments and are enjoying the incentives under the Renewable Energy Act of 2008. Solar Energy Solar Energy Service Contract (SESC) No. 2015-03-115 The SESC for the TSPP was awarded by the DOE on March 19, 2015. On June 17, 2015, PGEC and affiliate EEI Power Corporation (“EEIPC”, 100% subsidiary of EEI Corporation), incorporated PetroSolar to undertake the development of the TSPP. 50 MWDC Tarlac Solar Power Project-1 (TSPP-1) On June 22, 2015, PetroGreen and solar farm lot owner, Luisita Industrial Park Corporation (LIPCO), executed a Lease Agreement for the 55-hectare solar farm development. This was assigned to PetroSolar on September 15, 2015. As the LIPCO property is within the Central Technopark, which is under the jurisdiction of the Philippine Economic Zone Authority (PEZA), PetroSolar was able to register as an Ecozone Utilities Enterprise on July 28, 2015, entitling it to the incentives available to PEZA locators.

On February 8 to 27, 2021, the Maibarara-1 facility had a scheduled minor maintenance shutdown. Various maintenance activities for the unit’s mechanical and electrical, and instrumentation facilities, as well as for the switchyard and transmission lines, were carried-out by MGI technical staff and private contractors.

After only four (4) months of ground works, the TSPP-1 was completed by mid-January 2016 and was able to export power to the grid on January 27, 2016. The DOE eventually gave its Certificate of Endorsement (COE) - Feed-in-Tariff (FiT) for TSPP-1, with an official Commercial Operations Date on February 10, 2016. Subsequently, on April 6, 2016, PSC executed its Renewable Energy Payment Agreement (REPA) with the National Transmission Corporation (TransCo), assuring the TSPP-1’s revenues from the FiT payment of = P8.69/kWh from 2016 to 2036.

On the steamfield side, the two (2) production wells dedicated to MGPP-1 operations—Mai-6D and MB-12D—continued to behave consistently with dynamic but sustainable production.

The total energy exported to the grid was 71.93GWh and 66.00 GWh in 2020 and 2019, respectively.

MGPP-1 exported 165.10GWh and 162.09 GWh of electricity in 2020 and 2019, respectively. 12 MW Maibarara-2 Geothermal Power Plant (MGPP-2) With the stable performance of the reservoir, MGI decided to pursue an expansion of the MGPP. There was at least 5 MW of excess steam supply from the MGPP-1 wells, and with the ~6 MW capacity of the new well, an expansion of 12 MW was decided and approved in 2015 (MGPP-2).

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On February 8 to 13, 2021, the Maibarara-2 facility had its similar scheduled minor maintenance shutdown activities.

SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

The carrying value of the TSPP-1 solar plant amounted to P =2.34 billion and = P2.46 billion as of December 31, 2020 and 2019, respectively, and is pledged as mortgage property to the long-term loans obtained to finance the project (see Note 17). 20 MWDC Tarlac Solar Power Project (TSPP-2) On September 17, 2018, the BOI formally awarded to PetroSolar the latter’s Certificate of Registration for the 20 MWDC TSPP-2. This approval entitles the TSPP-2 to enjoy duty-free importation, seven-year Income Tax Holiday (ITH), among others.

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By the end of December 2018, civil works contractor, Media Construction and Development Corporation (MCDC), completed the site clearing, ground levelling, and compaction works for the whole 22-hectare TSPP-2 lot (likewise under a long-term lease agreement with LIPCO). All six (6) quadrants were turned over and accepted by Solenergy Systems Inc., the main EPC contractor. After the site construction works for the TSPP-2 were completed in March 2019 and its registration with the WESM was secured from the Independent Electricity Market Operator of the Philippines Inc. (IEMOP) on April 21, 2019, the TSPP-2 started exporting power to the grid on April 22, 2019 as part of its testing and commissioning activities. The Energy Regulatory Commission (ERC) conducted its technical inspections for the TSPP-2 on May 31, 2019, as part of PetroSolar’s of the Certificate of Compliance (COC) for TSPP-2. On February 27, 2020 and March 18, 2020, the DOE formally issued to PSC the Certificate of Confirmation of Commerciality (COCOC) and the Certificate of Endorsement (COE) for TSPP-2, respectively. The COE is a prerequisite to the issuance of the Certificate of Compliance (COC). The COC will determine the official Commercial Operations Date (COD) for TSPP-2. As of April 23, 2021, PSC is still awaiting the ERC’s approval and release of TSPP-2’s COC, which will determine the official COD for TSPP-2. The TSPP-2 exported a total of 29.75GWh and 19.03 GWh to the grid in 2020 and 2019, respectively. Collateral to Secure Borrowings In 2011, MGI acquired land areas from Science Park of the Philippines, Inc. and Philtown Properties, Inc. amounting to = P25.57 million and P =8.15 million, respectively, used as power plant site in the Maibarara Project Area in Sto. Tomas, Batangas. MGI has mortgaged its property consisting of real assets and chattel, with a total carrying value of =4.59 billion as of December 31, 2020, as collateral in favor of RCBC (the Lender), in relation to its P two (2) loan facilities (see Note 17). The breakdown of the above value is as follows:  

Real Assets (consisting of land, buildings, land improvements, machinery and equipment) = P4.47 billion; and Chattel (consisting mainly of other machinery and equipment, inventory, furniture and fixtures) =126.16 million. P

PetroSolar mortgaged all of its property, plant and equipment with carrying value of = P3.05 billion as collateral to secure its borrowings as of December 31, 2020 (see Note 17).

2020

=339,934,370 P (19,491,642) 320,442,728 =192,958,190 P

Details of deferred oil exploration costs as of December 31 follow: Cost Gabonese Oil Concessions (Note 10) SC No. 6A - Octon-Malajon Block SC. No. 75 - Offshore Northwest Palawan SC. No. 14 - C2 (West Linapacan) Northwest Palawan (Note 10) Accumulated impairment losses Gabonese Oil Concessions (Note 10) SC. No. 14 - C2 (West Linapacan) Northwest Palawan (Note 10)

2020

2019

P =342,755,717 157,745,711 28,041,968

=326,299,680 P 156,626,442 28,041,968

2,432,828 530,976,224

2,432,828 513,400,918

318,284,347

2,158,381 320,442,728 P =210,533,496

2,158,381 320,442,728 =192,958,190 P

Philippine Oil Operations – Development Phase Under the SCs entered into with the DOE covering certain petroleum contract areas in various locations in the Philippines, the participating oil companies (collectively known as “Contractors”) are obliged to provide, at their sole risk, the services, technology and financing necessary in the performance of their obligations under these contracts. The Contractors are also obliged to spend specified amounts indicated in the contract in direct proportion to their work obligations. However, if the Contractors fail to comply with their work obligations, they shall pay to the government the amount they should have spent, but did not, in direct proportion to their work obligations. The participating companies have Operating Agreements among themselves which govern their rights and obligations under these contracts.

P =513,400,918 51,842,975 (34,267,669) – – 530,976,224

2019 =570,262,558 P 19,606,158 (11,901,978) (45,074,178) (19,491,642) 513,400,918

*SGVFSM008891* SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

P =320,442,728 – 320,442,728 P =210,533,496

2019

As of December 31, 2020 and 2019, the participating interests of the Group in various Petroleum SC areas are as follows:

The movements in deferred oil exploration costs follow:

2020

The full recovery of these deferred costs is dependent upon the discovery of oil in commercial quantities from any of the petroleum concessions and the success of future development thereof.

11. Deferred Oil Exploration Costs

Cost Balances at beginning of year Additions Transfers to wells and platforms (Note 10) Transfers to intangible assets (Note 15) Write-off / relinquishment Balances at end of year

Accumulated impairment losses Balances at beginning of year Write-off / relinquishment Balances at end of year

SC 6A – Octon-Malajon Block SC 75 – Offshore Northwest Palawan

2020 16.667% 15.000%

2019 16.667% 15.000%

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SC 6A - Octon-Malajon Block This is one of the first exploration areas in offshore Palawan. It includes about 165,000 hectares of relatively shallow water areas where a string of wells has found non-commercial oil accumulations in varied reservoir horizons. DOE granted in June 2009 the final 15-year extension of the SC-6A service contract. In 2016, The Philodrill Corporation (Operator of the SC-6A Block), conducted Geological and Geophysical (G&G) evaluation of the northern portion of the contract area through broadband reprocessing of the 3D seismic dataset acquired in 2013, seismic interpretation works on the newly processed data, and quantitative interpretation (QI) works on the Octon datasets. These were carried over to 2017. Contractor DownUnder Geosolutions (DUG) finished the preliminary processing works of the 2013 3D seismic dataset and is currently integrating the new data for the QI works. In 2018, technical evaluation efforts continued in the north block, particularly the Malajon-Salvacion-Saddle Rock prospects, in which Seismic Attributes mapping yielded several turbiditic channel systems within the reservoir intervals. In 2019, Philodrill completed seismic interpretation and mapping works for the northern portion of the Octon-Malajon block, using recent and old SC 6A seismic data and subsurface data from the adjacent Galoc Field. In 2020, Philodrill engaged Dubai-based consultants LMKR to conduct Quantitative Interpretation (QI) works to determine possible drilling opportunities in the northern portion of the block (Malajon field); the results of which were provided to the consortium in January 2021. In parallel, Philodrill is also reviewing a third-party technical evaluation on the southern portion of the block for a potential farm-in opportunity. Service Contract 6A is set to run until 2024. SC 75 - Offshore Northwest Palawan Service Contract 75 (SC 75) was signed on December 27, 2013 with partners PXP Energy Corporation (50%) and PNOC-Exploration Corporation (35%). The block covers the West Philippine Sea with an area of 616,000 hectares. The work commitment for Sub-Phase (SP) 1, which ended on December 27, 2015, had been fulfilled with the completion of the following activities, 1) Acquisition of 2,235 line-km of 2D seismic data over SC 75 from March to April 2014 using the vessel M/V Voyager Explorer of SeaBird Exploration, and simultaneous acquisition of marine magnetic and gravity data, 2) Broadband processing of the 2D seismic data, which was completed in April 2015, 3) Processing and interpretation of gravity and magnetic data, which was completed in February 2015, and 4) Geological & Geophysical (G&G) studies, including 2D seismic interpretation, which was completed in July 2015. On September 9, 2015, the DOE advised the Consortium of its decision to place SC 75 under Force Majeure (FM) effective from the end of Sub-Phase 1 on December 27, 2015.

Activities in SC 51 has been dormant since 2015 after a failed drilling program and farm-in opportunity from Otto Energy. After Otto’s exit and failed negotiations between the remaining Consortium members and the DOE, the DOE formally approved the relinquishment of SC 51 on July 1, 2019. Prior to relinquishment, PetroEnergy owned 20.05% participating interest in SC 51. The other Consortium members were PHINMA Petroleum and Geothermal Inc. (PPGI) and Alcorn Petroleum and Minerals Corporation (APMC) with 33.35% and 46.60% participating interests, respectively. Due to the relinquishment, the Parent Company has written off the = P19.49 million deferred oil exploration cost, including the related allowance for impairment loss provided in 2018. 12. Investment in a Joint Venture The investment in a joint venture represents PetroGreen’s 40% interest in PetroWind, a company incorporated in the Philippines. The primary purpose of PetroWind is to carry on the general business of generating, transmitting and/or distributing power derived from renewable energy sources. The movements in the carrying value as of December 31 follow: Balance at beginning of year Share in net income of a joint venture Dividends received Share in other comprehensive income (loss) Balance at end of year

2019 2020 P =1,563,732,303 = P1,526,687,692 111,266,383 97,552,085 (40,000,000) (60,000,000) 214,758 (507,474) P =1,635,213,444 P =1,563,732,303

The cost of the investment in PetroWind amounted to = P514.04 million as of December 31, 2020 and 2019. The carrying value of the investment in PetroWind is equivalent to the Group’s 40% share in PetroWind’s equity, plus the fair value adjustment of = P764.49 million recognized when the Group lost control over PetroWind in 2014. Selected financial information of PetroWind as of December 31 follows: Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity

2019 2020 P =529,047,169 =786,649,690 P 3,714,662,991 3,646,444,029 (344,089,158) (452,136,793) (1,787,557,500) (2,047,596,275) P =2,112,063,502 = P1,933,360,651

On October 14, 2020, the Department of Energy (DOE) issued a formal notice to the SC 75 consortium, lifting the Force Majeure imposed since September 2015. Through this letter, the consortium was notified to resume its Work Program commitments under SC 75. SC 51 - East Visayas The block covers the East Visayan basin in two parcels aggregating 444,000 hectares.

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Summary of statements of comprehensive income of PetroWind for the years ended December 31 follows: Revenue (electricity sales and other income) Cost and expenses Income before tax Tax benefit (provision) Net income Group’s share in net income Other comprehensive income (loss) Group’s share other comprehensive income (loss)

2020 P =814,551,799 (537,899,312) 276,652,487 1,513,469 P =278,165,956 P =111,266,383

2019

2018

P832,679,152 = (589,046,283) 243,632,869 247,342 =243,880,211 P =97,552,085 P

P869,231,086 = (567,412,396) 301,818,690 (4,695,793) =297,122,897 P =118,849,159 P

P =536,894

(P =1,268,685)

–

P =214,758

(P =507,474)

–

Wind Energy Service Contract (WESC) No. 2009-09-002 The service contract for the Nabas Wind Power Project (NWPP) covers 2,000 hectares of public and private lands in rolling terrain located near the northwestern tip of Panay Island. It lies about 6 km southeast of Caticlan, and electricity-deficient Panay and Boracay islands are natural markets of future power from Nabas or the Nabas WESC. In 2012, activities were focused on securing critical government permits, completing technical feasibility studies and initiating requests for engineering, procurement and construction bids. PetroGreen incorporated PetroWind on March 6, 2013 to undertake the NWPP. It was decided that the NWPP will be constructed in two phases: Phase 1 for the existing 36 MW NWPP-1, consisting of 18 Wind Turbine Generators (WTG); while Phase 2 will be a 14 MW development that will have seven (7) WTGs (NWPP-2). On May 26, 2013, the DOE issued the Confirmation of Commerciality for the 36 MW NWPP-1, making it the third WESC to be declared commercially feasible. This converted the Nabas WESC from the PreDevelopment Stage to the Development Stage, enabling PetroWind to proceed with the construction and development of the NWPP-1. EEI Corporation (EEI) was engaged to conduct the civil works consisting of the construction of the access roads, temporary landing pad and the WTG foundation. Cendaur Engineering was contracted to undertake the construction of the transmission line and substation. Gamesa Eolica SL Unipersonal, a Spanish company, and its Philippine Branch were engaged to supply, transport and install the WTGs. Construction of NWPP-1 started in December 2013 and was completed in the first half of 2015. On March 24, 2015, NWPP-1 successfully energized and dispatched power from 8 WTGs (WTGs 18) to the Visayas grid. On April 17, 2015, the DOE issued its Nomination for FIT Eligibility of NWPP1. The DOE also released on April 30, 2015, its Certificate of Endorsement (COE) for the NWPP-1, which is one of the requirements for the ERC to process PetroWind’s COC application for the NWPP1 and for FIT eligibility. By June 2015, all 18 WTGs became operational. On June 16, 2015, the DOE released the COE for FIT Eligibility (COE-FIT), endorsing the official start of commercial operation to be June 10, 2015. The ERC also completed the site visit for the DOE’s COE-FIT validation on June 24-25, 2015. On August 17, 2015, the ERC approved PWEI’s COC for NWPP-1. This confirms the commercial operations date of the wind farm to be June 10, 2015.

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In 2017, recently-merged WTG supplier, Siemens Gamesa Renewable Energy (SGRE), completed the following maintenance works on site: a) 24-month WTG maintenance in June; b) 30-month WTG maintenance in November; c) semi-annual electrical maintenance in October; and d) several and specific corrective works on the WTG blades and electrical modules. Major and long-lead equipment spares, such as WTG transformer, generator, and gearbox, were acquired to avoid long and unplanned shutdowns due to sudden equipment failure, similar to those that recently plagued other Philippine wind developers. SGRE completed its 36-Month WTG maintenance works, which started on April 16, 2018. The annual preventive maintenance works for the 69-kV electrical facilities (Substation, Switching Station, and Control Building equipment) were also completed on April 21-22, 2018. To maintain operational efficiency of the windfarm, O&M contractor SGRE completed its 48-Month (48M) and 54-Month (54M) WTG maintenance works in April and October 2019, respectively. In parallel, the annual preventive maintenance for the 69-kV electrical facilities was also conducted by Airnergy and Renewables, Inc. from April 11 to 12, 2019. On December 25, 2019, Typhoon Ursula (with international name Phanfone) hit the Visayas region, affecting several WTGs. These were put back on line in January to February 2020. In 2020, SGRE completed its 60-Month (60M) and 66-Month (66M) WTG maintenance works in June and October 2020, respectively. In parallel, the annual preventive maintenance for the 69-kV electrical facilities was also conducted by Airnergy and Renewables, Inc. from June 13 to 14, 2020. The annual total energy exported to the grid were 80.45 GWh, 110.09 GWh, and 114.55 GWh in 2020, 2019, and 2018 respectively. On May 13, 2020, the DOE formally awarded to PetroWind the Certificate of Confirmation of Commerciality (COCOC) for the planned 14-MW Nabas-2 Wind Power Project (NWPP-2). This signifies that NWPP-2 has been approved for construction as being commercially feasible. Throughout 2020, PetroWind carried out the following activities for NWPP-2; namely 1) third-party technical and commercial review of EPC proposals, and 2) environmental permit application from DENR to allow construction of NWPP-2 inside the Northwest Panay Peninsula Natural Park (NWPPNP). On February 17, 2021, the DENR-EMB Region 6 issued the amended Environmental Compliance Certificate (ECC) to PetroWind for NWPP-2. In parallel, PWEI is also advancing its offtake negotiations for NWPP-2 with local Visayas electric cooperatives and private retail electricity suppliers. 13. Leases The Group entered into lease contracts for office spaces and land used as geothermal field and photovoltaic (PV) solar power facility. The office space lease agreements are for a period of two (2) years and are renewable by mutual agreement of both parties. The land lease agreement (LLA) with NPC and PSALM for the geothermal field in Sto. Tomas, Batangas has a lease term of twenty-five (25) years, extendable for another 25 years upon mutual agreement of both parties.

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The two lease agreements with Luisita Industrial Park Corporation (LIPCO) for land used for the photovoltaic solar power facility in Tarlac is for a period of 25 years, renewable by mutual agreement of both parties, generally under the same terms and conditions, with escalation clause of 3% every 2 years. The Group’s obligations under these leases are secured by the lessor’s title to the leased assets. The Group is restricted from assigning and subleasing the leased assets. The Group applies the ‘short-term lease’ and ‘lease of low-value assets’ recognition exemptions for all other leases, including leases of vehicles and parking slots. The rollforward analyses of right-of-use assets follow:

Cost Beginning balance Additions Ending balance Accumulated depreciation Beginning balance Depreciation (Notes 21 and 23) Ending balance Net Book Value

Cost Depreciation (Notes 21 and 23) Net Book Value

Land

2020 Office Spaces

Total

=420,180,224 P – 420,180,224

P6,563,033 = 3,159,213 9,722,246

=426,743,257 P 3,159,213 429,902,470

20,053,149 20,144,675 40,197,914 =379,982,310 P

3,295,407 3,377,024 6,672,431 =3,049,815 P

23,348,556 23,521,789 46,870,345 =383,032,125 P

Land =420,180,224 P 20,053,149 =400,127,075 P

2019 Office Spaces =6,563,033 P 3,295,407 =3,267,626 P

Total =426,743,257 P 23,348,556 =403,394,701 P

The depreciation of the right-of-use of the lands in Tarlac and Batangas are presented as part of “Cost of electricity sales” while the depreciation of the right-of-use of office spaces are presented as part of “General and administrative expenses” in the consolidated statement of comprehensive income. In 2019, prior to the technical feasibility and commercial viability of TSPP-2, a portion of the depreciation of right-of-use assets and interest expense on lease liabilities amounting to P =1.99 million and P =4.29 million respectively, were capitalized as part of deferred development costs (see Note 15). No lease liability was recognized for leases of land that have been prepaid. The rollforward analyses of lease liabilities follow: Beginning balance Payments Interest expense Additions Ending balance Less current portion Noncurrent portion

2020 P =337,829,549 (36,596,442) 31,058,783 3,159,213 335,451,103 15,393,725 P =320,057,378

2019 =342,107,039 P (36,338,378) 32,060,888 – 337,829,549 18,974,634 =318,854,915 P

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The following are the amounts recognized in the consolidated statements of comprehensive income: Interest expense on lease liabilities Depreciation expense of right-of-use assets Rent expense - short-term leases Rent expense - low-value assets

2020 P =31,058,783 23,521,789 5,082,037 184,500 P =59,847,109

2019 =32,060,888 P 23,348,556 4,446,083 202,697 =60,058,224 P

Shown below is the maturity analysis of the undiscounted lease payments as of December 31: Within one year After one year but not more than five years More than five years but less than 10 years

2020 P =35,458,737 140,054,372 583,479,239 P =758,992,348

2019 P36,596,442 = 137,003,891 618,990,077 =792,590,410 P

14. Investment Properties As of December 31, 2020 and 2019, this account consists of land and parking lot space (located in Tektite) with cost amounting to = P1.61 million. The fair value of the investment properties of the Group is between P =1 million to P =1.70 million as of December 31, 2020 and 2019. The Group determined the fair values of the Group’s investment properties on the basis of recent sales of similar properties in the same areas as the investment properties and taking into account the economic conditions prevailing at the time the valuations were made. As of December 31, 2020 and 2019, the fair value of the investment properties is classified under the Level 2 category. Except for insignificant amounts of real property taxes on the investment properties, no other expenses were incurred, and no income was earned in relation to the investment properties in 2020, 2019 and 2018. 15. Other Noncurrent Assets Input VAT Intangible assets Restricted cash Deferred development costs Advances to contractors Others Less allowance for probable losses (Note 23)

2020 P =213,491,296 165,976,162 44,833,232 3,855,595 1,311,357 22,595,698 452,063,340 6,629,046 P =445,434,294

2019 =222,338,316 P 181,192,511 47,360,677 6,605,103 31,201,988 19,358,112 508,056,707 1,657,261 =506,399,446 P

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Input VAT Input VAT represents VAT passed on from purchases of goods and services that can be claimed against any future liability to the Bureau of Internal Revenue (BIR) for output VAT from sale of goods and services.

Restricted cash The restricted cash pertains to the Parent Company’s share in the escrow fund for the abandonment of the Etame Marine Permit amounting to = P41.80 million (or $870,200) and = P44.16 million (or $870,200) as of December 31, 2020 and 2019, respectively. - 49 Restricted cash The restricted cash pertains to the Parent Company’s share in the escrow fund for the abandonment of the Etame Marine Permit amounting to = P41.80 million (or $870,200) and P =44.16 million (or $870,200) as of December 31, 2020 and 2019, respectively. This also includes escrow to secure payment and discharge of the Parent Company’s obligations and liabilities under the FPSO contract amounting to P =3.03 million and = P3.20 million as of December 31, 2020 and 2019, respectively. The amount for the share in escrow of the Parent Company’s obligation for the FPSO was deducted from the Parent Company’s share on lifting proceeds during the first lifting made by Etame in November 2002 and will be paid back to the Parent Company at the end of the contract in 2022. Deferred development costs These pertains to costs incurred in the exploration, development, production and expansion of renewable energy projects. Balances at beginning of year Additions Write-offs (Notes 23 and 33) Transfers to property, plant and equipment (Note 10) Balances at end of year

2020 P =6,605,103 3,210,454 (5,959,962) – P =3,855,595

2019 =26,012,923 P 39,144,180 – (58,552,000) =6,605,103 P

Input VAT also includes outstanding input VAT claims that were applied by MGI for refund with the BIR. As of December 31, 2020 and 2019, the outstanding input VAT claims which are still pending with the CTA and SC amounted to = P126.96 million. Intangible assets Intangible assets pertain to land rights, which refers to grant of easement of right of way entered by PetroSolar to construct, operate, maintain, repair, replace and remove poles, wire, cables, apparatus, and equipment and such other apparatus and structures needed for the transmission line. This also includes software licenses of the Group.

Cost: Balances at beginning of year Additions Balances at end of year Accumulated Amortization: Balances at beginning of year Amortization Balances at end of year Net Book Values

Cost: Balances at beginning of year Additions Reclassifications from deferred oil exploration costs (Note 11) Balances at end of year Accumulated Amortization: Balances at beginning of year Amortization Balances at end of year Net Book Values

Land Rights

2020 Production Software and License Others

Total

P =152,249,710 – 152,249,710

P =45,074,178 – 45,074,178

P =40,827,262 2,102,105 42,929,367

P =238,151,150 2,102,105 240,253,255

23,852,454 6,089,989 29,942,443 P =122,307,267

4,622,993 4,622,993 9,245,986 P =35,828,192

28,483,192 6,605,472 35,088,664 P =7,840,703

56,958,639 17,318,454 74,277,093 P =165,976,162

2019 Production Software and License Others

Total

Land Rights =152,239,710 P 10,000

= P– –

=31,015,759 P 9,811,503

=183,255,469 P 9,821,503

– 152,249,710

45,074,178 45,074,178

– 40,827,262

45,074,178 238,151,150

17,761,299 6,091,155 23,852,454 =128,397,256 P

– 4,622,993 4,622,993 =40,451,185 P

18,065,487 10,417,705 28,483,192 =12,344,070 P

35,826,786 21,131,853 56,958,639 =181,192,511 P

Amortization expense charged to profit or loss follows: Cost of electricity sales (Note 21) General and administrative expenses (Note 23) Oil production operating expenses (Note 22)

2020 P =8,060,685

2019 =10,726,337 P

2018 =11,414,196 P

4,634,776

5,782,523

2,064,244

4,622,993 P =17,318,454

4,622,993 =21,131,853 P

– =13,478,440 P

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Accounts payable Accrued expenses Utilities Interest (Note 17) Professional fees Sick/vacation leaves Profit share Due to related party (Note 25) Others Withholding taxes and other tax payables Provision for probable loss (Note 23) Due to NRDC Others

2020 P =108,742,621

2019 =139,167,931 P

138,895,513 46,686,129 20,110,749 17,373,564 8,019,499 1,192,620 7,053,531 12,502,369 3,566,020 2,269,737 1,169,357 P =367,581,709

68,310,651 54,130,576 8,792,995 15,807,702 7,087,209 145,600 5,157,806 40,038,233 1,051,178 2,269,737 1,756,456 =343,716,074 P

This also includes escrow to secure payment and discharge of the Parent Company’s obligations and liabilities under the FPSO contract amounting to P =3.03 million and = P3.20 million as of December 31, 2020 and 2019, respectively. The amount for the share in escrow of the Parent Company’s obligation for the FPSO was deducted from the Parent Company’s share on lifting proceeds during the first lifting made by Etame in November 2002 and will be paid back to the Parent Company at the end of the contract in 2022. *SGVFSM008891*

Deferred development costs These pertains to costs incurred in the exploration, development, production and expansion of renewable energy projects. Balances at beginning of year Additions Write-offs (Notes 23 and 33) Transfers to property, plant and equipment (Note 10) Balances at end of year

2020 P =6,605,103 3,210,454 (5,959,962) – P =3,855,595

2019 =26,012,923 P 39,144,180 – (58,552,000) =6,605,103 P

Advances to contractors Advances to contractors pertain to the downpayments to various contractors for the purchase of materials and equipment. Others Other noncurrent assets pertain to noncurrent portion of prepaid insurance and security deposits. 16. Accounts Payable and Accrued Expenses Accounts payable Accrued expenses Utilities Interest (Note 17) Professional fees Sick/vacation leaves Profit share Due to related party (Note 25) Others Withholding taxes and other tax payables Provision for probable loss (Note 23) Due to NRDC Others

2020 P =108,742,621

2019 =139,167,931 P

138,895,513 46,686,129 20,110,749 17,373,564 8,019,499 1,192,620 7,053,531 12,502,369 3,566,020 2,269,737 1,169,357 P =367,581,709

68,310,651 54,130,576 8,792,995 15,807,702 7,087,209 145,600 5,157,806 40,038,233 1,051,178 2,269,737 1,756,456 =343,716,074 P

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Accounts payable mainly consists of payable to suppliers and contractors that are currently involved in the development, construction and operations of energy projects. Accounts payable also include unclaimed checks pertaining to dividends payable amounting to = P10.66 million as of December 31, 2020 and 2019 (see Note 30). The Group’s accounts payable and accrued expenses are due within one year.

The loan is payable every 17th of May and November beginning on May 2017. The agreement further specifies that 96.50% of the aggregate principal amount shall be paid on the due date of the loan.

17. Loans Payable

On November 29, 2016, PetroGreen has drawn an additional P =30.00 million out of the total loan facility. The additional loan from Chinabank has an annual interest rate of 5.33%.

The Group’s loans payable as of December 31 follow: Principal, balance at beginning of year Add availments during the year Less principal payments during the year Principal, balance at end of year Less unamortized deferred financing cost Less current portion - net of unamortized deferred financing cost Noncurrent portion

2020 P =5,360,170,129 778,500,000 1,369,699,350 4,768,970,779 40,766,823 4,728,203,956

2019 =5,752,190,910 P 548,500,000 940,520,781 5,360,170,129 60,331,266 5,299,838,863

855,279,695 P =3,872,924,261

1,197,555,427 =4,102,283,436 P

PetroEnergy’s short-term loans payable PetroEnergy entered into unsecured loan agreements specifically to finance its Etame Expansion Project and investments in Renewable Energy Projects. Omnibus Credit Line Agreement (OCLA) with the Development Bank of the Philippines (DBP) PetroEnergy entered into unsecured loan agreements specifically to finance its Etame Expansion Project and investments in Renewable Energy Projects. On April 27, 2015, PetroEnergy entered into an OCLA with the DBP which provides a credit facility in the principal amount not exceeding = P420.00 million. On June 29, 2016 the credit facility was increased to P =500.00 million. Loans payable to DBP are as follows: As of December 31, 2020:  P =78.50 million with interest rate of 5.5% and maturity on May 14, 2021; and As of December 31, 2019:  P =78.50 million with interest rate of 6.0% and maturity on May 19, 2020; and  P =190.00 million with interest rate of 6.0% and maturity on April 27, 2020. Short-term Loan with Rizal Commercial Banking Corporation (RCBC) In 2020, PetroEnergy obtained a clean loan from RCBC amounting to = P150.00 million with interest rate of 4.5% and maturing on November 15, 2021. Interest expense related to these loans amounted to = P17.02 million, = P20.36 million and = P28.13 million in 2020, 2019 and 2018, respectively. Accrued interest payable amounted to P =1.16 million and =2.22 million as of December 31, 2020 and 2019, respectively (see Note 16). P

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PetroGreen’s long-term loans payable Credit Line Facility with Chinabank On November 17, 2015, PetroGreen entered into a 5-year credit line facility with Chinabank amounting to = P500.00 million, subject to repricing on the third anniversary. On the same date, = P400.00 million out of the total loan facility were drawn by PetroGreen. The loan has an annual interest rate of 5.24% and has no collateral.

On November 17, 2018, the = P400.00 million and = P30.00 million long-term loans payable with interest rate of 5.24% and 5.33%, respectively, were repriced to 8.28% and 8.47%. In 2019, PetroGreen negotiated for the reduction in the interest rates of the aforementioned loans from 8.28% and 8.47% to 7.14% for both loans. The reduced interest rate was approved by the bank and made effective starting September 19, 2019. This amendment did not result to an extinguishment of the loan. As of December 31, 2019, outstanding balance of the loan, net of unamortized deferred financing costs, amounted to = P416.45 million. The loan was paid in 2020. Long-term loan with RCBC On November 16, 2020, PetroGreen obtained a new long-term unsecured loan with RCBC amounting to = P400.00 million. The proceeds from this loan was used to pay the outstanding = P417.10 million loan from Chinabank. The new loan bears interest at a fixed rate of 4.74% payable semi-annually. The principal amount is payable in five equal annual installments starting November 11, 2021. As of December 31, 2020, the outstanding balance of the loan, net of unamortized deferred financing costs, amounted to = P397.93 million. Interest expense related to these loans amounted to = P31.47 million, = P34.84 million and = P26.39 million in 2020, 2019 and 2018, respectively. Accrued interest payable amounted to P =2.13 million and =3.28 million as of December 31, 2020 and 2019, respectively (see Note 16). P MGI’s long-term loans payable Project Loan Facility Agreements with RCBC On May 19, 2016, MGI, together with PetroGreen, PHINMA and PNOC RC executed the Project Loan Facility Agreement with RCBC for a P =1,400.00 million project loan to finance the design, development and construction of MGPP-2 or M2. On September 5, 2016, MGI, together with PetroGreen, PHINMA and PNOC RC executed another Project Loan Facility Agreement with RCBC for a P =2,100.00 million project loan to finance the design, development and construction of MGPP-1 or M1. This was done to consolidate the outstanding principal of the term loan under the 2011 OLSA with RCBC and BPI, incidental costs, general corporate expenditures and working capital requirement. a. MGPP-1 or M1 new Loan The new MGPP-1 or M1 loan amounting to P =2,100.00 million has a term of ten (10) years from the drawdown date of October 10, 2016. Interest and principal are payable semi-annually. Interest

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payment started on October 12, 2016, while the twenty (20) semi-annual principal payments started on April 12, 2017. Interest rate is fixed for the first five (5) years from drawdown date, based on the sum of the prevailing 5-year fixed benchmark rate on the pricing date and the margin of 1.75% (the “Initial Interest Rate”). On the repricing date, the interest for the remaining five (5)-year term of the loan will be the higher of (i) the sum of then prevailing 5-year fixed benchmark rate plus the margin of 1.75%, or (ii) the initial interest rate. As of December 31, 2020 and 2019, the outstanding balance of this loan amounted to = P1,465.00 million and = P1,623.00 million, respectively. Interest expense recognized from the new M1 Loan amounted to = P94.05 million, P =105.45 million and P =117.94 million in 2020, 2019 and 2018, respectively. b. MGPP-2 or M2 Expansion Loan The MGPP-2 or M2 Expansion Loan amounting to = P1,400.00 million has a term of twelve (12) years including thirty-six (36) months grace period from initial drawdown date of June 2, 2016. Interest and principal are payable semi-annually. Interest payment started on October 12, 2016, while the eighteen (18) semi-annual principal payments started on October 12, 2019. Interest rate is fixed for the first seven (7) years from the initial drawdown date based on the sum of the prevailing 7-year fixed benchmark rate on the pricing date and the applicable margin of (1) 2.25% per annum prior to commercial operations date, or (2) 1.75% per annum from and after the Commercial Operations Date (the “Initial Interest Rate”). For subsequent drawdowns, interest rate will be the three (3) –day simple average interpolated rate based on the remaining tenor and computed using the straight-line method. On the repricing date, the interest for the remaining five (5)-year term of the loan will be the higher of (i) the sum of the then prevailing 5-Year fixed benchmark rate plus the applicable margin, or (ii) the weighted average interest rate during the first seven (7) years of the loan. As of December 31, 2020 and 2019, the outstanding balance of this loan amounted to =1,204.11 million and = P P1,321.54 million, respectively. Interest expense amounted to =92.71 million, P P =92.54 million and P =62.04 million in 2020, 2019 and 2018, respectively. Capitalized interest, on the other hand, amounted to ₱29.04 million in 2018 (nil in 2020 and 2019). Accrued interest payable of MGI’s loans amounted to P =35.46 million and P =39.49 million as of December 31, 2020 and 2019, respectively (see Note 16). The loan covenants covering the outstanding debt of MGI include, among others, the following conditions: maintenance at all times of Debt-to-Equity (DE) Ratio of not greater than 70:30, Default Debt Service Coverage Ratio (DSCR) of at least 1.10x both until full payment of the Loans, and Dividend DSCR of at least 1.20x. MGI is also required to transfer in the DSPA equivalent to onesixth (1/6) of the amount sufficient to pay for the forthcoming debt service scheduled in April and October of every year until the loan is fully paid off (see Note 9). As of December 31, 2020 and 2019, MGI has been compliant with the above conditions. PetroSolar’s long-term loans payable On November 12, 2015, the PetroSolar, together with PetroGreen and EEIPC, as third party mortgagors and pledgors, entered into a = P2,600.00 million OLSA with PNB and DBP specifically to partially finance the design, development, procurement, construction, operation and maintenance of its TSPP.

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PetroSolar shall fully pay the loan for the pro-rata account of each lender within twelve (12) years from and after the date of the initial drawdown. Interest and principal are payable semi-annually. Interest payment started on May 27, 2016, while the twenty-two (22) semi-annual principal payments started on November 27, 2016. The rate of the interest applicable to the facility or the relevant part thereof for each interest period shall be fixed for the first seven periods (7) from the initial drawdown date (the Initial Interest Rate). Prior to the FIT entitlement and collection of FIT revenues of the borrower, the rate shall be the higher of: (i) the aggregate of the seven (7) year PDST-R2 and the initial credit spread of 2.25%, or (ii) the minimum interest rate of 5.75%. Upon FIT entitlement of at least 40MW and collection of FIT revenues by the borrower equivalent to an aggregate of at least P =473.00 million within a period not exceeding twelve (12) consecutive months, the rate shall be the higher of (i) the weighted average interest rate in previous drawdowns less the step down credit spread of 0.25%, or (ii) minimum interest rate, and which interest rate shall be applied beginning the following month immediately succeeding the month wherein the aforesaid FIT entitlement and FIT revenue collection thresholds were satisfied. PetroSolar met the criteria for FIT entitlement and aggregate collection of at least P =473 million within 12 months which resulted to a lower interest rate effective July 2017. The applicable interest rate for 2020 and 2019 is equal to 6.71%. The loan covenants covering the outstanding debt of PetroSolar include, among others, maintenance of debt-to-equity ratio of 75:25 and establishment of DSPA required balance (see Note 9). As of December 31, 2020 and 2019, PetroSolar is in compliance with the said loan covenants. As of December 31, 2020 and 2019, the outstanding balance of this loan amounted to = P1,448.54 million and P =1,667.64 million, respectively. Interest expense recognized amounted to P =120.94 million, =131.14 million and P P =157.90 million in 2020, 2019 and 2018, respectively. Accrued interest payable amounted to = P7.92 million and = P9.14 million as of December 31, 2020 and 2019, respectively (see Note 16). PetroSolar mortgaged all of its property and equipment related to TSPP-1 as collateral in connection with the loan (see Note 10). Deferred financing costs Deferred financing costs are incidental costs incurred in obtaining the loan which includes documentary stamp tax, transfer tax, chattel mortgage, real estate mortgage, professional fees, arranger’s fee and other costs directly attributable in obtaining the loan. The balance of unamortized deferred financing costs is presented as a deduction from the loans payable account and is amortized over the term of the loan using the effective interest rate method. Details of the Groups’ unamortized deferred financing costs follow: Balance at beginning of year Deferred financing costs on loans drawn during the year Less amortization during the year Balance at end of year

2020 P =60,331,266

2019 =79,276,809 P

2,150,538 62,481,804 (21,714,981) P =40,766,823

2,152,159 81,428,968 (21,097,702) =60,331,266 P

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18. Asset Retirement Obligation The Group has recognized its share in the abandonment costs associated with the Etame, Avouma and Ebouri oilfields located in Gabon, West Africa, geothermal field located in Sto. Tomas Batangas, and photovoltaic (PV) solar power facility in Tarlac. Movements in this account follow: 2020 P =90,621,021 17,448,816 4,129,022 (3,039,180) P =109,159,679

Balance at beginning of year Change in estimates (Note 10) Accretion expense Foreign exchange adjustment Balance at end of year

2019 =63,156,679 P 24,609,005 4,505,825 (1,650,488) =90,621,021 P

Details of the Group’s asset retirement obligation as of December 31 follow:

PetroEnergy MGI PetroSolar

2020 Discount Rate Amount 2.84% P =64,070,738 3.41% 31,209,163 3.92% 13,879,778 P =109,159,679

2019 Discount Rate Amount 4.39% P55,571,203 = 4.83% 24,562,064 5.17% 10,487,754 =90,621,021 P

19. Equity Under the existing laws of the Republic of the Philippines, at least 60% of the Parent Company’s issued capital stock should be owned by citizens of the Philippines for the Parent Company to own and hold any mining, petroleum or renewable energy contract area. As of December 31, 2020 and 2019, the total issued and subscribed capital stock of the Parent Company is 99.89% Filipino and 0.11% non-Filipino. As of December 31, 2020 and 2019, paid-up capital consists of: Capital stock - P =1 par value Authorized - 700,000,000 shares Issued and outstanding Additional paid-in capital

=568,711,842 P 2,156,679,049 =2,725,390,891 P

The Group’s track record of capital stock follows:

Listing by way of introduction August 11, 2004 Add (deduct): 25% stock dividend 30% stock dividend

Number of shares registered

Issue/offer price

Date of SEC approval

84,253,606

=3/share P

August 4, 2004

21,063,402 31,595,102

P1/share = =1/share P

September 6, 2005 September 8, 2006

Number of holders as of year-end

1:1 stock rights offering December 31, 2010 Deduct: Movement December 31, 2011 Deduct: Movement December 31, 2012 Deduct: Movement December 31, 2013 Deduct: Movement December 31, 2014 Add (Deduct): 2:1 stock rights offering December 31, 2015 Deduct: Movement December 31, 2016 Deduct: Movement December 31, 2017 Add (Deduct): 1.2:6 stock rights offering December 31,2018 Deduct: Movement December 31,2019 Deduct: Movement December 31,2020

Number of shares registered 136,912,110 273,824,220 − 273,824,220 − 273,824,220 − 273,824,220

Number of holders as of year-end

Issue/offer price =5/share P

Date of SEC approval May 26, 2010

136,912,110 410,736,330 − 410,736,330 − 410,736,330

=4.38/share P

June 3, 2015

(15) 2,028 (1) 2,027 (15) 2,012

157,975,512 568,711,842 − 568,711,842 − 568,711,842

=4.8/share P

January 8, 2018

(8) 2004 (5) 1,999 (1) 1,998

273,824,220

2,149 (26) 2,123 (10) 2,113 (41) 2,072 (29) 2,043

On July 26, 2017, at the BOD meeting, the Parent Company was authorized to raise approximately one billion pesos (P =1,000,000,000) in capital, by offering and issuing to all eligible stockholders as of record date, the rights to subscribe up to all of the existing unissued common shares of the Parent Company (“ Stock Rights Offer”). On September 29, 2017, the Parent Company filed its application for the listing and trading of rights shares with the PSE. On December 13, 2017, the PSE approved the application to list the Rights Shares. The rights offer entitled eligible stockholders as of record date of January 12, 2018 to subscribe to one rights share for every 2.6 shares held at an offer price of P =4.80 per share. The rights offer was undertaken on January 22 to 26, 2018. Following the close of the offer period, the Parent Company successfully completed the stock rights offer for 157,975,512 common shares with gross proceeds of = P758.28 million and was subsequently listed on the PSE on February 2, 2018. The proceeds from the stock rights offer were used for the development and expansion plans of the Group’s renewable energy projects, general corporate requirements, and payments of loans and the related interest. Appropriated Retained Earnings On January 15, 2008, the BOD approved the appropriation of P =20.00 million for the development of the Ebouri oilfield in Gabon, West Africa in addition to the = P30.00 million originally appropriated amount. On July 24, 2008, the BOD approved additional appropriation of retained earnings amounting to =44.14 million for the development of the Ebouri oil field in Gabon, West Africa. P

(Forward)

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On February 19, 2013, the BOD approved additional appropriated retained earnings amounting to =44.45 million to cover for the Group’s share in the cost of the committed wells in the Etame oilfield P in Gabon, West Africa. On July 12, 2018, the BOD approved the reversal of the appropriation amounting to = P138.59 million to unappropriated retained earnings since the above appropriations have been served. Dividends On July 26, 2018, the Parent Company declared cash dividends amounting to = P28,435,592 or = P0.05 per share to stockholders of record as of August 24, 2018 and was paid on September 20, 2018 (nil in 2019 and 2020). Cumulative Translation Adjustment In 2018, because of the change in business circumstances of the Parent Company, management changed its functional currency from United States Dollar (USD) to PHP effective January 31, 2018. All resulting exchange differences in the remeasurement of USD balances to PHP balances were recognized as ‘Cumulative Translation Adjustment’. Equity Reserve On June 9, 2015, PetroEnergy sold its 10% interest in PetroGreen to EEIPC, bringing its ownership in PetroGreen from 100% to 90%. The transaction was accounted as an equity transaction since there was no change in control. The effect of change in the ownership interest in PetroGreen on the equity attributable to owners of PetroEnergy is summarized as follows: Consideration received from non-controlling interest Carrying amount of non-controlling interest sold, net of related cost Excess of consideration received recognized in equity

P206,000,000 = (125,950,762) =80,049,238 P

Capital Management The primary objective of the Group’s capital management is to ensure that it maintains a strong credit rating and healthy capital ratios in order to support its business and maximize shareholders’ value. The Group manages its capital structure and makes adjustments to it, in light of changes in economic conditions. To maintain or adjust the capital structure, the Group may increase its debt from creditors, adjust the dividend payment to shareholders or issue new shares. As of December 31, 2020 and 2019, the Group monitors capital using a debt-to-equity ratio, which is total liabilities divided by total equity. The Group’s sources of capital as of December 31 are as follows: Loans payable Capital stock Additional paid-in capital Retained earnings Equity reserve

2020 2019 P =4,728,203,956 P =5,299,838,863 568,711,842 568,711,842 2,156,679,049 2,156,679,049 2,337,064,060 2,017,651,639 80,049,238 80,049,238 P =9,870,708,145 = P10,122,930,631

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The table below demonstrates the debt-to-equity ratio of the Group as of December 31: 2020 P =5,568,758,749 7,830,917,715 0.71:1

Total liabilities Total equity Debt-to-equity ratio

2019 =6,098,412,780 P 7,265,810,016 0.84:1

Based on the Group’s assessment, the capital management objectives were met in 2020 and 2019. 20. Income Tax The provision for (benefit from) income tax consists of: 2020 P =35,668,914 6,192,798 P =41,861,712

Current Deferred

2019 =15,054,689 P (2,874,875) =12,179,814 P

2018 =18,067,256 P 95,224 =18,162,480 P

The components of the Group’s net deferred tax assets (liabilities) are as follows: Deferred income tax assets on: Asset retirement obligation Accrued retirement liability Unrealized foreign exchange loss Interest on FIT adjustment Accrued interest on tax assessment Deferred income tax liabilities on: Oil production revenue Asset retirement cost Net retirement asset Deferred income tax assets - net

2020

2019

P =23,215,810 2,738,915 1,061,129 656,037 131,100 27,802,991

=19,787,726 P 2,408,273 1,193,492 – – 23,389,491

(10,527,097) (9,929,356) (1,694,713) (22,151,166) P =5,651,825

(3,349,064) (7,416,435) – (10,765,499) =12,623,992 P

As of December 31, 2020 and 2019, the Group did not recognize deferred tax assets on NOLCO and MCIT as the Group believes that it may not be probable that sufficient taxable income will be available in the near foreseeable future, prior to their expiration, against which the tax benefits can be realized. Details of the NOLCO and MCIT follow: Year Incurred 2020 2019 2018

NOLCO =173,156,951 P 80,176,058 58,106,412 =311,439,421 P

Expiry Year 2025 2022 2021

MCIT P755,543 = 2,329,516 2,759,239 =5,844,298 P

Expiry Year 2023 2022 2021

On September 30, 2020, the BIR issued Revenue Regulations No. 25-2020 implementing Section 4 (bbbb) of “Bayanihan to Recover As One Act” which states that the NOLCO incurred for taxable years 2020 and 2021 can be carried over and claimed as a deduction from gross income for the next five (5) consecutive taxable years immediately following the year of such loss.

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Movements in NOLCO follow: Beginning balances Additions Expiration Ending balances

21. Cost of Electricity Sales 2020 P =287,334,725 173,156,951 (149,052,255) P =311,439,421

2019 =381,104,630 P 80,176,058 (173,945,963) =287,334,725 P

2020 P =5,335,472 755,543 (246,717) P =5,844,298

2019 P3,232,966 = 2,329,516 (227,010) =5,335,472 P

Movements in MCIT follow: Beginning balances Additions Expiration Ending balances

For MGI, as indicated on the Implementing Rules and Regulations of the Renewable Energy (RE) Act of 2008, the NOLCO of the RE Developer during the first three (3) years from the start of commercial operation shall be carried over as a deduction from gross income for the next seven (7) consecutive taxable years immediately following the year of such loss, subject to the following conditions: a) The NOLCO had not been previously offset as a deduction from gross income; and b) The loss should be a result from the operations and not from the availment of incentives provided for in the RE Act. For PetroSolar, on July 28, 2015, the PSC registered with PEZA as an Economic Zone Utilities Enterprise to establish, operate and maintain its 50MW Solar Facility project at the Central Technopark and the sale of electricity in accordance with the representations, commitments and proposals set forth in its application. PetroSolar shall pay the special tax rate of 5% on its gross income earned from sources within the PEZA economic zone in lieu of paying all national and local income taxes. Gross income earned refers to gross sales derived from any business activity, net of returns, discounts and allowances, less cost of sales, cost of production and allowable expenses as defined by PEZA. Income generated from sources outside of PEZA economic zone shall be subject to Regular Corporate Income Taxes (RCIT). The reconciliation of the statutory tax rate to the effective income tax rate shown in the consolidated statements of income follows: Statutory tax rate Add (deduct) reconciling items: Income from entities subjected to lower rate Nondeductible expenses Movement in unrecognized deferred tax assets Income subjected to final tax Unrealized loss on FVTPL Nontaxable income Others Effective income tax rate

2020 30.00% (31.51) 1.05 7.65 (0.78) (0.03) – (0.30) 6.08%

2019 30.00%

2018 30.00%

(21.50) 1.60

(14.83) 0.79

4.91 (2.42) (0.01) – (10.35) 2.23%

11.80 (2.49) (0.07) (18.05) (4.60) 2.55%

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Depreciation and amortization (Notes 10, 13 and 15) Purchased services and utilities Rental, insurance and taxes Personnel costs Repairs and maintenance Materials and supplies Government share and royalty fees Business and other related expenses

2020

2019

2018

P =422,437,239 240,261,428 113,001,690 67,663,684 29,031,090 14,768,942

P406,532,430 = 119,305,171 108,363,449 70,579,509 53,529,903 16,417,339

=342,966,989 P 107,426,125 119,598,185 70,691,373 26,903,476 27,304,016

13,859,060

13,066,762

12,094,267

8,554,125 P =909,577,258

17,900,019 =805,694,582 P

14,199,841 =721,184,272 P

Government share Under the Service Contract, the RE Developer shall pay the government share equivalent to one and a half percent (1.5%) from the sale of geothermal steam and one percent (1%) from the sale of solar energy produced and such other income incidental to and arising from generation, transmission and sale of electric power generated from geothermal energy within the Contract Area less costs and expenses incurred thereon. Energy Regulation No. 1-94 (ER 1-94) Based on ER 1-94, all power producer shall set aside one-centavo per kilowatt-hour (P =0.01/kwh) of the total electricity sales of the energy-generating facility which shall be applied to Generation Facilities and/or energy resource development projects located in all barangays, municipalities, cities, provinces and regions. This is included under “Rental, insurance and taxes.” 22. Crude Oil Inventory and Oil Production Crude Oil Inventory Crude oil inventory is stated at NRV at the time of production. Change in crude oil inventory amounting to (P =23.93 million), (P =2.37 million) and P =22.80 million is included in “Cost of Sales” in the profit or loss in 2020, 2019 and 2018, respectively. Oil Production Production, transportation and other related expenses Storage and loading expenses Amortization (Note 15) Supplies and facilities Others

2020

2019

2018

P =154,375,753 48,958,540 4,622,993 245,499 3,325,006 P =211,527,791

=162,893,096 P 48,659,191 4,622,993 317,481 4,766,595 =221,259,356 P

=194,336,353 P 42,986,631 − 310,395 5,061,752 =242,695,131 P

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23. General and Administrative Expenses Salaries, wages and benefits Research costs (Note 15) Depreciation and amortization (Notes 10, 13 and 15) Professional and other fees Provision for probable losses (Notes 15 and 16) Taxes and licenses Communication Entertainment, amusement and recreation Insurance Transportation and travel Gasoline, oil and lubricants Donation and contribution Security and janitorial services Advertisement Environmental and social expenses Repairs and maintenance Condominium dues Stock transfer expense Office supplies Utilities Rent expense (Note 13) Business meetings Dues and subscriptions Training and seminar Other services Others

2020 P =88,316,619 20,732,859

2019 =86,593,321 P 2,428,039

2018 =79,440,639 P 4,286,192

19,826,663 16,150,382

19,047,451 16,377,334

10,733,686 50,145,356

14,667,316 12,981,759 4,899,998

6,889,792 25,544,000 4,809,611

12,553,048 3,649,424 4,527,004

3,864,188 3,275,568 2,788,254 2,592,010 2,438,521 1,858,409 1,721,551

5,852,679 3,221,453 5,121,820 2,632,511 2,484,110 2,205,419 1,733,416

5,477,813 2,311,921 7,186,379 2,358,781 1,512,730 1,586,178 1,171,144

1,641,585 1,462,835 1,344,109 1,248,905 1,207,607 1,130,369 894,632 392,771 325,755 166,739 97,920 5,374,887 P =211,402,211

2,181,745 1,519,353 1,327,547 2,238,317 1,782,023 1,967,063 791,891 1,310,651 516,748 2,509,070 139,389 21,988,863 =223,213,616 P

2,917,179 1,324,698 1,321,855 4,413,970 1,907,846 2,107,922 4,137,614 1,133,477 306,877 4,461,364 243,809 6,246,593 =217,463,499 P

Others, include miscellaneous expenses such as wheeling charges, development assistance, notarization, bank charges, and reproduction expenses. 24. Miscellaneous Income (Charges) Management income and timewriting fees (Note 25) Trustee fees Rental income (Note 25) Professional fees (Note 25) Gain on sale of equipment Dividend income (Note 8) Others

2020 P =13,252,890 (4,169,361) 857,143 550,000 662,857 71,770 651,378 P =11,876,677

2019 =10,517,125 P (5,157,836) 857,143 550,000 345,134 61,586 509,063 =7,682,215 P

2018 P8,408,310 = (4,041,061) 857,143 − 500,830 83,050 546,710 =6,354,982 P

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Trustee fees pertain to payments of the Group to the facility agent and account trustees for the M1 and M2 loans (see Note 17). 25. Related Party Transactions Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party in making financial and operating decisions or the parties are subject to common control or common significant influence (referred to as ‘Affiliates’). Related parties may be individuals or corporate entities. Significant transactions with related parties are as follows:

Related Party/Nature Investor House of Investments, Inc Internal audit services

Transactions for the Years Ended December 31 2020 2019

Outstanding Balance Receivables (Payables) (see Notes 7 and 16) 2020 2019

=1,483,821 P

=739,200 P

(P =1,192,620)

857,143 11,252,890 2,000,000 8,301,126

857,143 8,517,125 2,000,000 8,984,672

− 578,331 − 123,577 701,908

Affiliate AC Energy Corporation (ACEN) Electricity sales 1,044,249,958 Wheeling Charges 116,377,508

Joint Venture PetroWind Rental income Timewriting fee Management income Advances

Affiliate EEI Power Corporation Other income

=550,000 P

Terms and Conditions

(P =145,600)

Note a

− 1,411,611 − 202,904 1,614,515

Note b Note c Note c Note d

1,139,162,750 −

103,806,730 104,098,660 12,584,870 − 116,391,600 104,098,660

Note e Note e

=550,000 P

=1,232,000 P =616,000 P =117,132,888 P P =106,183,575

Note f

a. PetroEnergy has an Internal Audit Engagement arrangement with House of Investments, Inc. (HI). The internal audit services amounted to = P873,600 and = P739,200 for 2020 and 2019, respectively. In 2020, HI rendered additional internal audit service amounting to = P610,221 (nil in 2019). These are non-interest bearing and are due and demandable. b. PetroGreen charges rental fees to PetroWind amounting to = P71,429 every month. These are non-interest bearing and payable when due and demandable. c. Timewriting fees are charged by PetroGreen for accounting, legal management and other support services rendered to PetroWind. Management income refers to charges by PetroEnergy to PetroWind. These are non-interest bearing and are due and demandable.

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d. Advances represent reimbursements of costs and expenses. e. Electricity sales to ACEN (formerly PHINMA) is pursuant to the Electricity Supply Agreement (see Note 33). This is due and payable on the last business day of the month succeeding the billing period and non-interest bearing if paid within the due date. f.

The methods and assumptions used by the Group in estimating the fair value of financial instruments are:

In 2020 and 2019, PetroGreen charged EEI Power Corporation (EEIPC) amounting to ₱550,000 plus VAT representing charges for the equity valuation study.

g. In 2019, EEIPC granted a loan to PetroSolar amounting to = P123.20 million with an interest rate of 5.50% per annum. The loan was converted into equity for subscription of unissued authorized capital stock in July 2019 increasing non-controlling interest (see Note 29). h. On November 12, 2015, PetroSolar entered into a P =2.6 billion OLSA with PNB and DBP. PetroGreen and EEIPC signed as the third party mortgagors and pledgors (see Note 17). i.

PetroWind executed an OLSA with DBP for a loan facility amounting to P =3.0 billion. PetroEnergy signed as guarantor and PetroGreen signed as guarantor, pledgor and third-party mortgagor.

Compensation of Key Management Personnel The Group has a profit-sharing plan for directors, officers, managers and employees as indicated in its by-laws. The amount, the manner and occasion of distribution is at the discretion of the BOD, provided that profit share shall not exceed 5% of the audited income before income tax and profit share. The remuneration of the Group’s directors and other members of key management are as follows: Salaries and wages and other short-term benefits Directors’ fees Retirement expense

2020

2019

2018

P =20,962,298 5,674,198 2,242,667 P =28,879,163

=23,883,304 P 5,417,248 2,033,795 =31,334,347 P

=23,142,849 P 5,804,539 2,537,817 =31,485,205 P

26. Financial Instruments The Group’s principal financial instruments include cash and cash equivalents, financial assets at FVTPL, receivables, restricted cash, loans payable, accounts payable, accrued expenses and dividends payable. The main purpose of these financial instruments is to fund the Group’s working capital requirements. Categories and Fair Values of Financial Instruments As of December 31, 2020 and 2019, the carrying amounts of the Group’s financial assets and financial liabilities approximate their fair values except for loans payable and lease liabilities. The fair value of the loans payable as of December 31, 2020 and 2019 amounted to P =4.83 billion and = P5.45 billion compared to their carrying value of P =4.73 billion and P =5.36 billion, respectively. As of December 31, 2020 and 2019, the fair value of lease liabilities amounted to = P466.80 million and = P397.22 million compared to the carrying value of = P335.45 million and = P337.83 million, respectively.

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Financial instruments Cash and cash equivalents, restricted cash, receivables, accounts payable and accrued expenses, and short-term loans payable

Considerations Due to the short-term nature of the instruments, carrying amounts approximate fair values as at the reporting date.

Equity securities

Fair values are based on published quoted prices.

Golf club shares

Fair values are based on quoted market prices at reporting date.

Long-term loans payable

Fair value is based on the discounted value of expected future cash flows using the applicable interest rate for similar type of instruments. The fair value is derived using the prevailing PH BVAL rate in 2020 and 2019.

Lease liabilities

Estimated fair value is based on the discounted value of future cash flows using the prevailing PH BVAL rate in 2020 and 2019.

The fair value is based on the source of valuation as outlined below:   

quoted prices in active markets for identical assets or liabilities (Level 1); those involving inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly (Level 2); and those with inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).

In 2020 and 2019, there were no transfers of financial instruments among all levels. Financial Risk Management Objectives and Policies The Group manages and maintains its own portfolio of financial instruments in order to fund its own operations and capital expenditures. Inherent in using these financial instruments are the following risks on liquidity, market and credit. Financial Risks The main financial risks arising from the Group’s financial instruments are liquidity risk, market risk and credit risk. Liquidity Risk Liquidity risk is the risk that the Group is unable to meet its financial obligations when due. The Group monitors its cash flow position and overall liquidity position in assessing its exposure to liquidity risk. The Group maintains a level of cash and cash equivalents deemed sufficient to finance its operations and to mitigate the effects of fluctuation in cash flows. To cover its short-term and long-term funding requirements, the Group intends to use internally generated funds as well as to obtain loan from financial institutions. As of December 31, 2020 and 2019, the Group has existing credit line facilities from which they can draw funds from (see Note 17).

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The tables below summarize the maturity profile of the Group’s financial assets and financial liabilities as of December 31, 2020 and 2019 based on contractual payments: 2020 Financial Assets Financial assets at FVTPL Financial assets at amortized cost: Cash and cash equivalents Accounts receivable Other receivables Interest receivable Refundable deposits Restricted cash Financial Liabilities Financial liabilities at amortized cost: Loans payable** Lease liabilities Accounts payable and accrued expenses* Net financial assets (liabilities)

*Excluding statutory payables **Includes future interest payments

On demand

1 year or less

More than 1 year

= P7,531,587

= P−

= P7,531,587

1,267,332,044 29,035,850 − 895,945 − 154,118,649 1,458,914,075

− 240,119,247 − − 324,721 394,892,804 635,336,772

− 994,603 2,526,250 − 16,583,984 44,833,232 64,938,069

1,267,332,044 270,149,700 2,526,250 895,945 16,908,705 593,844,685 2,159,188,916

− −

855,988,810 35,383,562

4,093,526,940 723,514,761

4,949,515,750 758,898,323

416,485,403 416,485,403 = P1,042,428,672

− 891,372,372 (P = 256,035,600)

2019 Financial Assets Financial assets at FVTPL Financial assets at amortized cost: Cash and cash equivalents Accounts receivable Interest receivable Other receivables Refundable deposits Restricted cash Financial Liabilities Financial liabilities at amortized cost: Loans payable** Lease liabilities Accounts payable and accrued expenses* Net financial assets (liabilities)

*Excluding statutory payables **Includes future interest payments

− 4,817,041,701 (P = 4,752,103,632)

416,485,403 6,124,899,476 (P = 3,965,710,560)

More than 1 year

=8,240,096 P

=− P

=8,240,096 P

1,066,698,077 70,683,906 253,077 − − 152,036,942 1,297,912,098

− 232,525,972 1,095,301 27,968,537 324,721 443,837,452 705,751,983

− 362,830 − − 15,980,288 47,360,677 63,703,795

1,066,698,077 303,572,708 1,348,378 27,968,537 16,305,009 643,235,071 2,067,367,876

5,476,849,755 619,157,476 − 6,096,007,231 (P =6,032,303,436)

Financial liabilities Accounts payable and accrued expenses Net exposure

2019

Peso Equivalent

US Dollar

$504,969 627,158 933,325 2,065,452

P24,256,708 = 30,126,160 44,833,232 99,216,100

$1,825,094 1,392,423 933,325 4,150,842

=92,611,861 P 70,657,092 47,360,677 210,629,630

276,820 $1,788,632

13,297,309 P85,918,791 =

933,283 $3,217,559

47,358,522 =163,271,108 P

Peso Equivalent

As of December 31, 2020 and 2019, the exchange rates used for conversion are = P48.036 and =50.744 per $1, respectively. P

Total

6,998,119,608 790,954,930 296,712,831 8,085,787,369 (P =6,018,419,493)

b. Market Risk Market risk is the risk of loss on future earnings, on fair values or on future cash flows that may result from changes in market prices. The value of a financial instrument may change as a result of changes in equity prices, foreign currency exchanges rates, interest rates and other market changes. Foreign Exchange Risk Foreign currency risk is the risk that the value of the Group’s financial instruments denominated other than the Group’s functional currency diminishes due to unfavorable changes in foreign exchange rates. The Group’s transactional currency exposures arise from cash and cash equivalents, receivables and accounts payable and accrued expenses.

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Financial assets Cash and cash equivalents Receivables Restricted Cash

2020

The following table demonstrates the sensitivity to a reasonably possible change in US dollar exchange rates. With all other variables held constant, the effect on the Group’s income before income tax is as follows:

1 year or less

1,521,269,853 171,797,454 214,781,270 1,907,848,577 (P =1,202,096,594)

US Dollar

Total

On demand

− − 81,931,561 81,931,561 = P1,215,980,537

The Group’s foreign currency-denominated financial instruments as of December 31, 2020 and 2019 follow:

2020 2019

Increase/(decrease) in foreign currency +5% -5% +4% -4%

Effect on income before income tax (P =4,585,135) 4,585,135 (P =6,131,492) 6,131,492

There is no other impact on the Group’s equity other than those already affecting income before income tax. Interest Rate Risk The Group’s exposure to market risk for changes in interest rates relates primarily to the Group’s loans payable. Interest rate of loans payable is fixed for the first five (5) years or first seven (7) years and will be repriced thereafter. The table demonstrates the sensitivity to a reasonably possible change in interest rates, with all other variables held constant, of the Group’s net income. The Group used the forecasted one-year Treasury bill rate in performing the analysis. Loans payable Increase/decrease in interest rate (in basis points) +50% to 195% -50% to -195%

2020

Impact on income before tax (P =47,544,391) 47,544,391

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Increase/decrease in interest rate (in basis points) +38% to +60% -38% to -60%

2019

- 67 irrespective of the timing of the default (a lifetime ECL). In its ECL models, the Group relies on a broad range of forward-looking information as economic inputs.

Impact on income before tax (P =43,402,513) 43,402,513

The inputs and models used for calculating ECLs may not always capture all characteristics of the market at the date of the financial statements. To reflect this, qualitative adjustments or overlays are occasionally made as temporary adjustments when such differences are significantly material.

There is no other impact on the Group’s equity other than those already affecting income before income tax.

The table below shows the aging by class of asset for the Group’s financial assets and contract asset as of December 31, 2020 and 2019:

c. Credit Risk Credit risk is the possibility of loss for the Group if its receivable counterparties fail to discharge their contractual obligations. With respect to credit risk arising from the other financial assets of the Group, which comprise of cash and cash equivalents, receivables, financial assets at FVTPL, and restricted cash, the Group’s exposure to credit risk could arise from default of the counterparty. The Group trades only with recognized, creditworthy third parties. However, the Group’s credit risk exposure is concentrated on a few counterparties as inherent in the oil exploration and production and renewable energy businesses. The Group has a well-defined credit policy and established credit procedures. In addition, receivable balances are being monitored on a regular basis to ensure timely execution of necessary intervention efforts. The table below summarizes the Group’s gross maximum credit risk exposure from its financial instruments and contract asset. These amounts are gross of collateral and credit enhancements, but net of any amounts offset and allowance for impairment losses: Financial assets: Cash in banks and cash equivalents Receivables Financial assets at FVTPL Refundable deposits Restricted cash Contract asset

2020

2019

P =1,263,308,043 273,571,895 7,531,587 16,908,705 593,844,685 146,067,517 P =2,301,232,432

=1,066,396,874 P 332,889,623 8,240,096 16,305,009 643,235,071 − =2,067,066,673 P

An impairment analysis is performed at each reporting date using a provision matrix to measure ECL. The mechanics of the ECL calculations and the key elements are, as follows: a. Probability of default (PD) is an estimate of the likelihood of default over a given time horizon. b. Exposure at default (EAD) is an estimate of the exposure at a future default date taking into account expected changes in the exposure after the reporting date. c. Loss given default (LGD) is an estimate of the loss arising in the case where a default occurs at a given time. ECLs are recognized in two stages. For credit exposures for which there has not been a significant increase in credit risk since initial recognition, ECLs are provided for credit losses that result from default events that are possible within the next 12-months (a 12-month ECL). For those credit exposures for which there has been a significant increase in credit risk since initial recognition, a loss allowance is required for credit losses expected over the remaining life of the exposure,

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Current

Financial assets: Cash and cash equivalents* P1,263,308,043 = Accounts receivable 270,149,700 Other receivables 2,526,250 Interest receivable 895,945 Financial assets at FVTPL 7,531,587 Refundable deposits 16,908,705 Restricted cash 593,844,685 Contract asset 146,067,517 =2,301,232,432 P

2020 More than 90 days

Credit impaired

Total

= P− − − −

= P− = P1,263,308,043 2,682,452 272,832,152 − 2,526,250 − 895,945

− − − − = P−

− 7,531,587 − 16,908,705 − 593,844,685 − 146,067,517 =2,682,452 P P =2,303,914,884

*excluding cash on hand

Financial assets: Cash and cash equivalents* Accounts receivable Interest receivable Other receivables Financial assets at FVTPL Refundable deposits Restricted cash

Current

2019 More than 90 days

Credit impaired

Total

=1,066,396,874 P 303,572,708 1,348,378 27,968,537

P− = − − −

=− = P P1,066,396,874 2,682,452 306,255,160 − 1,348,378 − 27,968,537

8,240,096 16,305,009 643,235,071 =2,067,066,673 P

− − − =− P

− 8,240,096 − 16,305,009 − 643,235,071 =2,682,452 P P =2,069,749,125

*excluding cash on hand

Financial assets are classified as high grade if the counterparties are not expected to default in settling their obligations. Thus, credit risk exposure is minimal. Financial assets are classified as a standard grade if the counterparties settle their obligation with the Group with tolerable delays. Low grade accounts are accounts, which have probability of impairment based on historical trend. These accounts show propensity of default in payment despite regular follow-up actions and extended payment terms. The Group’s cash in banks, cash equivalents, accounts receivable, interest receivable and restricted cash have high grade credit quality.

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27. Segment Information For management purposes, the Group is organized into business units based on their products and has four reportable segments as follows:    

The oil production segment is engaged in the oil and mineral exploration, development and production. The geothermal energy segment develops and operates geothermal steamfields and power plants. The solar energy segment carries out solar energy operations of the Group. Other activities pertain to research and investment activities.

No operating segments have been aggregated to form the above reportable operating segments. Management monitors the operating results of its business units separately for the purpose of making decisions about resource allocation and performance assessment. Segment performance is evaluated based on operating profit or loss and is measured consistently with operating profit or loss in the consolidated financial statements. Oil Geothermal Production Energy = P292,573,199 P = 1,160,627,466 (93,295,082) 282,923,201 3,490,089 (6,516,645)

2020 Solar Energy P = 879,290,407 413,412,580 111,889

Other Activities =– P 197,987,673 1,331,146

Elimination Consolidated = P– P = 2,332,491,072 (154,837,152) 646,191,220 – (1,583,521)

Segment revenue Net income (loss) Other comprehensive income (loss) Other information: Segment assets except deferred tax assets = P3,446,590,391 P = 5,910,320,833 = P4,294,097,136 P = 2,759,679,512 (P = 3,016,663,233)P = 13,394,024,639 Deferred tax assets - net = P777,332 = P3,969,332 = P905,161 =– P =– P = P5,651,825 Segment liabilities except deferred tax liabilities = P338,912,834 P = 2,969,012,990 = P1,835,356,905 P = 425,683,647 (P = 207,627) = P5,568,758,749 Deferred tax liabilities - net =– P =– P =– P =– P =– P =– P Cash flows from (used in): Operating activities = P17,492,817 P = 831,655,309 P = 645,745,818 (P = 14,762,230) (P = 954,252) = P1,479,177,462 Investing activities (84,758,970) (151,529,604) (21,805,235) 152,676,899 (114,545,748) (219,962,658) Financing activities (58,070,172) (555,675,630) (506,472,851) (53,045,442) 115,500,000 (1,057,764,095) Provision for (benefit from) income tax = P7,384,343 = P70,287 = P33,707,896 = P699,186 =– P = P41,861,712 Capital expenditures = P26,168,256 P = 162,001,340 P = 21,346,049 = P1,162,270 = P– P = 210,677,915 Deferred oil exploration costs = P210,533,496 =– P =– P =– P = P– P = 210,533,496 Depletion, depreciation and amortization = P95,845,289 P = 252,171,511 P = 176,667,277 = P4,731,938 (P = 292,587) = P529,123,428

Geothermal Energy P =1,139,162,750 321,474,746 (2,464,127)

2019

Other Activities =– P 203,929,129 (3,274,267)

Oil Production Solar Energy Elimination Consolidated Segment revenue = P351,057,274 = P631,944,707 = P– P =2,122,164,731 Net income (loss) 37,056,507 209,475,962 (238,003,688) 533,932,656 Other comprehensive loss 822,545 (531,118) – (5,446,967) Other information: Segment assets except deferred tax assets = P3,599,142,103 P =5,937,038,323 = P4,225,274,049 P =2,665,532,940 (P = 3,075,388,611)P =13,351,598,804 Deferred tax assets - net = P9,601,071 = P2,834,134 = P188,787 =– P =– P = P12,623,992 Segment liabilities except deferred tax liabilities = P410,483,292 P =3,201,001,838 = P2,054,341,913 P =433,089,051 (P = 503,314) = P6,098,412,780 Deferred tax liabilities - net =– P =– P =– P =– P =– P =– P Cash flows from (used in): Operating activities = P38,591,853 = P738,157,482 = P552,836,198 (P = 22,541,695) = P1,283,972 P =1,308,327,810 Investing activities 42,387,137 (308,157,013) (604,558,161) (24,382,378) 173,593,668 (721,116,747) Financing activities (31,601,092) (441,536,798) (121,287,399) 65,564,064 (174,877,640) (703,738,865) Provision for (benefit from) income tax (P = 839,974) (P = 61,826) = P12,523,711 = P557,903 =– P = P12,179,814 Capital expenditures = P36,519,811 = P264,104,747 = P647,523,109 = P2,343,099 (P = 1,125,911) = P949,364,855 Deferred oil exploration costs = P192,958,190 =– P =– P =– P = P– P =192,958,190 Depletion, depreciation and amortization = P68,072,511 = P256,012,915 = P157,983,213 = P4,618,436 (P = 639,002) = P486,048,073

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Segment revenue Net income (loss) Other comprehensive loss Other information: Segment assets except deferred tax assets Deferred tax assets - net (Forward)

Oil Production = P436,971,279 26,219,307 3,106,072

2018 Geothermal Other Energy Solar Energy Activities P =1,110,004,166 = P615,152,770 =– P 377,499,019 221,904,465 163,390,496 345,533 – –

Elimination Consolidated = P– = P2,162,128,215 (94,100,000) 694,913,287 – 3,451,605

= P3,527,423,273 P =5,855,498,457 = P3,649,347,629 P =2,472,755,316 (P = 2,775,878,178) = P12,729,146,497 = P7,342,003 = P2,344,578 = P806,575 =– P =– P = P10,493,156

Segment liabilities except deferred tax liabilities = P374,384,446 P =3,337,983,034 = P2,171,664,798 Deferred tax liabilities - net =– P =– P =– P Cash flows from (used in): Operating activities = P92,490,837 P =559,439,468 P =646,206,888 Investing activities (539,841,895) (139,072,317) (195,618,902) Financing activities 209,163,053 (328,649,582) (89,101,150) Provision for (benefit from) income tax = P3,891,103 (P = 902,758) P =14,816,069 Capital expenditures = P2,129,418 P =70,126,594 = P38,839,853 Deferred oil exploration costs = P230,328,188 =– P =– P Depletion, depreciation and amortization = P86,711,385 P =214,950,154 P =131,321,428

P =631,592,683 (P = 423,104,383) = P6,092,520,578 =– P =– P =– P (P = 22,399,774) = P10,749,646 = P1,286,487,065 (166,340,490) 310,342,477 (730,531,127) 148,011,052 (321,092,123) (381,668,750) = P358,066 =– P = P18,162,480 = P1,237,756 = P– P =112,332,621 =– P = P– P =230,328,188 = P1,813,819

= P–

P =434,796,786

InterGroup investments, revenues and expenses are eliminated during consolidation. 28. Basic/Diluted Earnings Per Share The computation of the Group’s earnings per share follows: Net income attributable to equity holders of the Parent Company Weighted average number of shares Basic/diluted earnings per share

2020

2019

2018

P =319,412,421

=292,835,761 P

=421,257,530 P

568,711,842 P =0.5616

568,711,842 =0.5149 P

568,711,842 =0.7407 P

Earnings per share are calculated using the net income attributable to equity holders of the Parent Company divided by the weighted average number of shares. PERC does not have potentially dilutive common stock. 29. Non-controlling Interests As of December 31, 2020 and 2019, non-controlling interests (NCI) pertain to the 10% shareholdings of EEIPC in PetroGreen, total shareholdings of ACEN (formerly PHINMA) [25%] and PNOC-RC (10%) in MGI and 44% shareholdings of EEIPC in PetroSolar.

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As of December 31, 2020 and 2019, the accumulated balances of and net income attributable to noncontrolling interests are as follows: Accumulated balances of non-controlling interests: PetroSolar MGI PetroGreen

Net income attributable to non-controlling interests: PetroSolar MGI PetroGreen

2020

2019

P =1,082,243,972 1,030,847,011 470,011,271 P =2,583,102,254

=955,293,206 P 958,604,717 424,441,329 =2,338,339,252 P

2020

2019

P =181,901,535 99,023,120 45,854,144 P =326,778,799

P92,169,424 = 112,516,161 36,411,310 =241,096,895 P

The summarized financial information of these subsidiaries is provided below in PHP which is the subsidiaries’ functional currency. This information is based on amounts before intercompany eliminations.

PetroSolar The 2020 and 2019 financial information for PetroSolar follows: Statements of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statements of Comprehensive Income Revenue Net income Total comprehensive income Statements of Cash Flows Net cash from (used in): Operating activities Investing activities Financing activities Effect of foreign exchange rate Net increase (decrease) in cash and cash equivalents

2020

2019

P =593,681,512 3,701,320,783 272,971,498 1,562,385,406 2,459,645,391

=505,633,639 P 3,719,829,197 275,302,122 1,779,039,791 2,171,120,923

P =879,290,407 413,412,580 413,524,468

=631,944,707 P 209,475,962 208,944,844

645,745,818 (21,805,236) (506,472,851) (249,572)

552,836,198 (604,558,161) (121,287,399) (2,588,425)

117,218,160

(175,597,787)

MGI

PetroGreen

The 2020 and 2019 financial information for MGI follow:

The 2020 and 2019 financial information for PetroGreen follows:

Statements of Financial Position Current assets Noncurrent assets Current liabilities Noncurrent liabilities Equity Statements of Comprehensive Income Revenue Net income Total comprehensive income Statements of Cash Flows Net cash from (used in): Operating activities Investing activities Financing activities Effect of foreign exchange rate Net increase (decrease) in cash and cash equivalents

2020

2019

P =1,202,138,803 4,712,151,362 596,645,785 2,372,367,206 2,945,277,174

=1,103,583,706 P 4,836,288,751 510,905,565 2,690,096,273 2,738,870,619

1,160,627,466 282,923,201 276,406,555

1,139,162,750 321,474,746 319,010,619

831,655,304 (151,529,599) (555,675,630) (14,423)

738,157,482 (308,157,013) (441,536,798) (12,186)

124,435,652

(11,548,515)

2020

2019

P =195,771,674 2,452,641,455 98,673,138 327,010,509 2,222,729,482

=107,470,601 P 2,460,510,254 427,456,320 5,632,731 2,134,891,804

191,332,639 86,721,290 87,837,678

196,454,123 106,377,044 103,610,251

(14,762,230) 152,676,899 (53,045,442) (54,831)

(22,541,695) (24,382,378) 65,564,064 43,789

84,814,396

18,683,780

Dividends paid to non-controlling interests amounted to = P79.50 million and = P76.00 million in 2020 and 2019, respectively.

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Increase in non-controlling interests from stock issuances

30. Consolidated Statements of Cash Flows

December 31, 2020: 

Changes in the Group’s liabilities arising from financing activities follow:

There was no movement in the capital stocks of the subsidiaries.

2020

December 31, 2019:    

On March 29, 2019, the SEC approved PetroGreen’s increase in authorized capital stock. PetroGreen applied the P =254.46 million deposits for future stock subscription as payment of stock. PetroGreen also received additional subscriptions amounting to P =156.80 million at par which increased the non-controlling interest by = P15.68 million. On April 15, 2019, the SEC approved PetroSolar’s increase in authorized capital stock. PetroSolar applied the = P454.50 million deposits for future stock subscription as payment of stock. PetroSolar also received subscriptions amounting to P =280.00 million at par which increased the non-controlling interest by = P123.20 million.

The increase in non-controlling interest from stock issuances did not result in dilution of the Parent Company’s effective interest in the subsidiaries. The SEC approved the application made by both PetroGreen and PetroSolar on March 29, 2019 and April 15, 2019, respectively. PetroGreen On September 12, 2018, PetroGreen’s BOD and stockholders approved the proposed increase in authorized capital stock from = P2.00 billion divided into 2 billion shares with a par value of = P1.00 per share to = P2.50 billion divided into 2.5 billion shares with the same par value per share. In 2018, PetroGreen received deposits for future stock subscriptions amounting to = P222.87 million at par, = P22.29 million of the total consideration was received from the non-controlling interests. In 2019, PetroGreen received an additional P =31.59 million deposits for future stock subscription which increased the non-controlling interest by = P3.16 million. The total deposits for future stock subscription amounting to = P254.46 million was reclassified as equity in 2019 upon approval by the SEC of the increase in authorized capital stock. PetroSolar On September 12, 2018, PetroSolar’s BOD and stockholders approved the proposed increase in authorized capital stock from = P1.00 billion divided into 1 million shares with a par value of P =100.00 per share to = P1.8 billion divided into 1.8 million shares with the same par value per share. In 2018, PetroSolar received deposits for future stock subscriptions amounting to = P397.98 million at par, = P175.11 million of the total consideration was received from the non-controlling interests. In 2019, PetroSolar received an additional = P56.52 million deposits for future stock subscription which increased the non-controlling interest by = P24.87 million.

2019 Loans payable P5,299,838,863 = Accrued interest payable 54,130,576 Lease liabilities 337,829,549 Dividends payable 10,666,514 = P5,702,456,002

Non-cash Changes Additional lease Dividend liabilities Deferred Cash Interest Interest declarations (Note 13) financing costs accretion expense to NCI flows 2020 =– P = 2,150,538 P P = 19,564,443 =– P = – (P P = 593,349,888)P = 4,728,203,956 – 3,159,213 – = P3,159,213

– – 340,873,318 – (348,317,765) 46,686,129 – – 31,058,783 – (36,596,442) 335,451,103 – – – 79,500,000 (79,500,000) 10,657,014 = P2,150,538 = P19,564,443 = P371,932,101 P = 79,500,000 (P = 1,057,764,095)P = 5,120,998,202

2019 Non-cash Changes Adoption of Declaration Deferred PFRS 16 of cash financing Cash Interest Interest Capitalized (Note 3) dividends** costs accretion expense interest flows 2019 =– P =– = P P2,152,159 = P18,945,543 =– P =– (P P = 394,172,940) P =5,299,838,863

2018 Loans payable P =5,672,914,101 Accrued interest payable 58,556,797 – – – – 358,550,724 – (362,976,945) 54,130,576 Lease liabilities – 342,107,039 – – – 27,767,974 4,292,914 (36,338,378) 337,829,549 Dividends payable 10,666,514 – 76,000,000 – – – – (76,009,500) 10,657,014 Due to a related party – – – – – 1,148,155 – (1,148,155) – = P5,742,137,412 = P342,107,039 = P76,000,000 = P2,152,159 = P18,945,543 = P408,081,530 P =4,292,914 (P = 870,645,918) P =5,702,456,002

In 2019, the Group also received cash from issuance of stocks to Non-controlling interests amounting to = P166.91 million (see Note 29). 2018

Loans payable Accrued interest payable Dividends payable Due to a related party

Non-cash Changes Deferred Declaration of Interest 2017 cash dividend* financing costs accretion =6,509,479,547 P =– P = P1,195,645 = P21,698,189

60,180,919 – – – 10,393,359 144,608,747 – – 39,422,055 – – – = P6,605,738,542 = P144,608,747 = P1,195,645 = P21,698,189 *Includes dividend declarations to non-controlling interests amounting to = P 65,900,000

Cash Interest expense flows 2018 =– (P P = 859,459,280) P =5,672,914,101 394,430,660 (396,054,782) 58,556,797 – (144,335,592) 10,666,514 1,337,333 (40,759,388) – = P395,767,993 (P = 1,440,609,042) P =5,742,137,412

In 2018, the Group also received cash from the following:  Issuance of stocks to Non-controlling interests amounting to = P12.50 million (see Note 29);  Deposits for future stock subscriptions on Non-controlling interests amounting to = P197.40 million (see Note 29); and  Issuance of stocks by the Parent Company amounting to = P758.28 million (see Note 29).

The total deposits for future stock subscription amounting to = P454.50 million was reclassified as equity in 2019 upon approval by the SEC of the increase in authorized capital stock.

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- 75 ix.

31. Renewable Energy Act of 2008 On January 30, 2009, Republic Act No. 9513, An Act Promoting the Development, Utilization and Commercialization of Renewable Energy Resources and for Other Purposes, otherwise known as the “Renewable Energy Act of 2008” (the “Act”), became effective. The Act aims to (a) accelerate the exploration and development of renewable energy resources such as, but not limited to, biomass, solar, wind, hydro, geothermal and ocean energy sources, including hybrid systems, to achieve energy selfreliance, through the adoption of sustainable energy development strategies to reduce the country’s dependence on fossil fuels and thereby minimize the country’s exposure to price fluctuations in the international markets, the effects of which spiral down to almost all sectors of the economy; (b) increase the utilization of renewable energy by institutionalizing the development of national and local capabilities in the use of renewable energy systems, and promoting its efficient and cost-effective commercial application by providing fiscal and non-fiscal incentives; (c) encourage the development and utilization of renewable energy resources as tools to effectively prevent or reduce harmful emissions and thereby balance the goals of economic growth and development with the protection of health and environment; and (d) establish the necessary infrastructure and mechanism to carry out mandates specified in the Act and other laws. As provided for in the Act, Renewable Energy (RE) developers of RE facilities, including hybrid systems, in proportion to and to the extent of the RE component, for both power and non-power applications, as duly certified by the DOE, in consultation with the Board of Investments (BOI), shall be entitled to the following incentives, among others: i.

Income Tax Holiday (ITH) - For the first seven (7) years of its commercial operations, the duly registered RE developer shall be exempt from income taxes levied by the National Government; ii. Duty-free Importation of RE Machinery, Equipment and Materials - Within the first ten (10) years upon issuance of a certification of an RE developer, the importation of machinery and equipment, and materials and parts thereof, including control and communication equipment, shall not be subject to tariff duties; iii. Special Realty Tax Rates on Equipment and Machinery - Any law to the contrary notwithstanding, realty and other taxes on civil works, equipment, machinery, and other improvements of a registered RE developer actually and exclusively used for RE facilities shall not exceed one and a half percent (1.5%) of their original cost less accumulated normal depreciation or net book value; iv. NOLCO - the NOLCO of the RE developer during the first three (3) years from the start of commercial operation which had not been previously offset as deduction from gross income shall be carried over as deduction from gross income for the next seven (7) consecutive taxable years immediately following the year of such loss; v. Corporate Tax Rate - After seven (7) years of ITH, all RE developers shall pay a corporate tax of ten percent (10%) on its net taxable income as defined in the National Internal Revenue Code of 1997, as amended by Republic Act No. 9337; vi. Accelerated Depreciation - If, and only if, an RE project fails to receive an ITH before full operation, it may apply for accelerated depreciation in its tax books and be taxed based on such; vii. Zero Percent VAT Rate - The sale of fuel or power generated from renewable sources of energy, the purchase of local goods, properties and services needed for the development, construction and installation of the plant facilities, as well as the whole process of exploration and development of RE sources up to its conversion into power shall be subject to zero percent (0%) VAT; viii. Cash Incentive of RE Developers for Missionary Electrification - An RE developer, established after the effectivity of the Act, shall be entitled to a cash generation-based incentive per kilowatthour rate generated, equivalent to fifty percent (50%) of the universal charge for power needed to service missionary areas where it operates the same;

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Tax Exemption of Carbon Credits - All proceeds from the sale of carbon emission credits shall be exempt from any and all taxes; and Tax Credit on Domestic Capital Equipment and Services - A tax credit equivalent to one hundred percent (100%) of the value of the VAT and custom duties that would have been paid on the RE machinery, equipment, materials and parts had these items been imported shall be given to an RE operating contract holder who purchases machinery, equipment, materials, and parts from a domestic manufacturer for purposes set forth in the Act.

RE developers and local manufacturers, fabricators and suppliers of locally-produced RE equipment shall register with the DOE, through the Renewable Energy Management Bureau (REMB). Upon registration, a certification shall be issued to each RE developer and local manufacturer, fabricator and supplier of locally-produced renewable energy equipment to serve as the basis of their entitlement to the incentives provided for in the Act. All certifications required to qualify RE developers to avail of the incentives provided for under the Act shall be issued by the DOE through the REMB. 32. Electric Power Industry Reform Act (EPIRA) After emerging from the crippling power crisis that occurred in the early 1990s, the Philippine Government embarked on an industry privatization and restructuring program envisioned to ensure the adequate supply of electricity to energize its developing economy. This restructuring scheme is embodied in RA No. 9136, the EPIRA. Approved on June 8, 2001, the EPIRA seeks to ensure quality, reliable, secure and affordable electric power supply; encourage free and fair competition; enhance the inflow of private capital; and broaden the ownership base of power generation, transmission and distribution. The Government viewed restructuring and reform as a long-term solution to the problems of the power sector. The huge investment requirement for new generation capacity and expansion of the necessary transmission and distribution network was estimated at an annual average of $1.0 billion. Given its own fiscal constraints, the Government recognized the need for greater private sector involvement in the power sector. Even though some private sector participation was successfully introduced earlier between the NPC and private investors, this time, the Government is envisioning addressing the power sector inefficiencies and the monopoly in the generation business. EPIRA mandated the overall restructuring of the Philippine electric power industry and called for the privatization of NPC. The restructuring of the electricity industry calls for the separation of the different components of the power sector, namely: generation, transmission, distribution, and supply. On the other hand, the privatization of the NPC involves the sale of the state-owned power firm’s generation and transmission assets (e.g. power plants and transmission facilities) to private investors. These two reforms are aimed at encouraging greater competition and attracting more private-sector investments in the power industry. A more competitive power industry will in turn result in lower power rates and a more efficient delivery of electricity supply to end-users. Specifically, the EPIRA has the following objectives:   

Achieve transparency with the unbundling of the main components of electricity services, which will be reflected in the consumers’ electricity rates; Opening up of the electricity market to competition at the wholesale (generation) level to improve efficiency in the operation of power plants and redound to lower electricity prices; Enhance further inflow of private capital and broaden ownership base in generation, transmission distribution, and supply of electric power;

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Establish a strong and independent regulatory body that will balance the interest of both the investors by promoting competition through creation of a level playing field and protect the electricity end-users from any market power abuses and anti-competitive behaviors; and Accelerate and ensure the total electrification of the country.

Crude Oil Sales and Purchase and Services Agreement (COSPA) with Exxon Mobil Sales and Supply LLC

Foreign Petroleum Operations

On December 20, 2019, the JV Partners signed a COSPA with Exxon Mobil Sales and Supply LLC (Exxon), a company incorporated under the laws of the State of Delaware and having its registered office at 251 Little Falls Drive, Wilmington DE 19808. The agreement is effective from February 1, 2020 until January 31, 2021. On December 14, 2020, the first amendment to the COSPA was executed, amending and extending the term of the COSPA with Exxon effective February 1, 2021 until July 31, 2021.

Oil revenue is recognized upon transfer of crude oil to the buyer at the delivery point.

Philippine Petroleum Operations

Exploration and Production Sharing Contract - Gabon, West Africa

The Group is part of various consortia for the following petroleum service contracts (see Notes 10 and 11):



33. Material Contracts and Agreements

The Etame permit consists of an offshore exploration area of 307,360 hectares that extends from depths of 200 meters in the Atlantic shelf to the near-shore Gabon. PetroEnergy, together with its joint venture partners (JV) composed of Addax Petroleum Etame, Inc. (formerly PanOcean Energy Gabon Corp.); Sasol Petroleum West Africa Limited; Tullow Oil Gabon S.A. and VAALCO Gabon S.A., has an existing Exploration and Production Sharing Contract (EPSC) with the Republic of Gabon in West Africa. The EPSC defines the rights and obligations of the Consortium in relation to the contract area, and governs the mutual relationship and establishes the rules and terms for exploration, exploitation and production sharing. After deduction by the consortium on a part of the Net Production for the recovery of the Petroleum Costs, the remaining hydrocarbon production is shared between the Consortium and the Gabonese Government, the rate of which depends on the level of production for a given calendar month. The Consortium is likewise subject to payment of royalties, the rate of which previously depended on the volume of production for a calendar month, ranging from 3% to 17.5%. Starting July 17, 2011, by virtue of an amendment to the EPSC, the rate was fixed at 13%. In the 6th amendment to the EPSC dated September 17, 2018, the Government of Gabon granted a ten (10)-year extension on the Consortium’s Exclusive Exploitations Areas under the EPSC, with two additional five (5)-year option periods.

Service Contract (SC) SC 6A Octon, Northwest Palawan SC 14-C2 West Linapacan SC 75 Offshore, Northwest Palawan Under the SCs entered into with the Department of Energy (DOE) covering the petroleum contract areas located in the Philippines described above, the participating oil companies (collectively known as “Contractors”) are obliged to provide, at their sole risk, the services, technology and financing necessary in the performance of their obligations under these contracts. The Contractors are also obliged to spend specified amounts indicated in the contract in direct proportion to their work obligations. Should the Contractors fail to comply with their work obligations, they shall pay to the government the amount they should have spent but did not in direct proportion to their work obligations. The participating companies have Joint Operating Agreements among themselves which govern their rights and obligations under these contracts.

Joint Operating Agreement - Gabon

At present, all of the above are in the exploration stage, and the Group, except as to SC 75, is carried free up to at least the drilling of the first well (see Note 11).

The Joint Operating Agreement (JOA) establishes the respective rights and obligations of the members of the Consortium with regard to the operations under the EPSC, including the joint exploration, appraisal, development and production of hydrocarbon reserves from the contract area. VAALCO has been appointed as the Operator of the field and shall continue to act as such until such time that all the JV Partners decide to appoint a new Operator from among them.

Renewable Energy Projects

Crude Oil Sales and Purchase and Services Agreement (COSPA) with Glencore Energy UK Ltd and Mercuria Energy Trading S.A.

Set out below is the disaggregation of the Group’s revenue from contracts with customers for the years ended December 31:

In 2015, the JV Partners signed a COSPA with Glencore Energy UK Ltd., a company incorporated in England. The initial agreement was effective from August 1, 2015 to July 31, 2016. There were several extensions until January 31, 2019. In January 2019, the JV Partners entered into a COSPA with Mercuria Energy Trading S.A., a company incorporated in Switzerland. The agreement is effective from February 1, 2019 to January 31, 2020.

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Revenues from sale of electricity using renewable energy is consummated and recognized over time whenever the electricity generated by the Group is transmitted through the transmission line designated by the buyer, for a consideration.

Revenue from electricity supply agreement Revenue sales under Feed-in-Tariff (FIT)

2020 P =1,160,627,466 879,290,407 P =2,039,917,873

2019 =1,139,162,750 P 631,944,707 =1,771,107,457 P

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Shareholders Agreement (SHA)

Omnibus Loan and Security Agreement (OLSA) with RCBC and BPI

On May 16, 2017, PetroGreen entered into a Shareholders Agreement (SHA) with EEI Power Corporation (EEIPC) and BCPG Wind Cooperatief U.A. (BCPG). The SHA governs the relations of these three companies as shareholders of PWEI and define their respective rights and obligations as such.

On September 26, 2011, MGI executed an OLSA with Rizal Commercial Banking Corporation (RCBC) and Bank of the Philippine Islands (BPI) for a = P2.40 Billion loan facility to fund the 70% loan portion of the project cost of MGPP 1. PetroGreen signed as sponsor, pledgor and third-party mortgagor.

Omnibus Loan and Security Agreement (OLSA) with DBP On November 4, 2013, PetroWind executed an OLSA with the Development Bank of the Philippines for a loan facility of up to = P2.8 billion to fund the 70% debt portion of the project cost of Nabas 1. PetroWind signed the OLSA as a borrower, while PetroGreen signed as a guarantor, pledgor and third-party Mortgagor. PetroEnergy likewise signed as a guarantor. The loan amount was later increased to P =3 billion. Renewable Energy Payment Agreement (REPA) Consequent to the issuance of FIT COC in its favor, PetroWind entered into a REPA with the National Transmission Corporation (TransCo) on July 30, 2015. Under the REPA, TransCo shall pay the FIT Rate of = P7.40/kWh for all metered generation of PetroWind for a period of twenty (20) years from start of Commercial Operations. Geothermal Renewable Energy Service Contract (GRESC) On February 1, 2010, PetroEnergy signed GRESC No. 2010-02-012 covering the Maibarara Geothermal Field in Laguna and Batangas areas, following a Philippine Energy Contracting Round for Geothermal held by the DOE in November 2009, where PetroEnergy emerged as the lone qualified bidder. On August 11, 2010, the SEC approved the incorporation of MGI, whose principal business is to develop and operate geothermal steam fields and power plants. The GRESC was then assigned to MGI. PetroEnergy, through PetroGreen, holds a 65% interest in MGI, while Trans-Asia Oil and Energy Development Corporation (“Trans-Asia”, subsequently renamed as PHINMA Energy Corporation or “PHINMA”, and now known as AC Energy Corporation or “ACEN”) and PNOC Renewables Corporation (PNOC RC) holds 25% and 10% interests, respectively. MGI developed the 20 MW MGPP-1, which was put on commercial operation on February 8, 2014. The MGPP-1 is the first commercial geothermal power facility under the administration of President Benigno S. Aquino, III and the first renewable energy (RE) project to go commercial under the 2008 RE Law. On March 9, 2018, MGI’s newly completed 12 MW MGPP-2 started exporting power to the Luzon Grid and official commenced commercial operations on April 30, 2018. On January 8, 2019, the ERC notified MGI that its application for the renewal of its COC for MGPP-1 and MGPP-2 was approved by the ERC En Banc on December 4, 2018.

= P 2.10 Billion Project Loan Facility Agreement (OLSA) with RCBC On September 5, 2016, MGI executed a = P2.10 Billion Project Loan Facility with RCBC to be used for the consolidation of MGI’s outstanding Term Loans under the 2011 OLSA and incidental costs in connection with the consolidation, and to finance the working capital requirements and other general corporate purposes of MGI. = P 1.40 Billion Project Loan Facility Agreement with RCBC On May 19, 2016, MGI entered into a P =1.40 Billion Project Loan Facility Agreement with RCBC to finance up to 70% of the Project Cost of the 12 MW MGPP-2. ESA for MGPP-1 and MGPP-2 On September 16, 2011 MGI executed an Electricity Supply Agreement (ESA-1) with Trans-Asia (now ACEN), wherein MGI agreed to sell to Trans-Asia (now ACEN) the entire generated output of MGPP1 for a period of 20 years commencing from commercial operations on February 8, 2014. On April 26, 2016, MGI entered into another Electricity Supply Agreement (ESA-2) with Trans-Asia (then renamed as PHINMA Energy Corporation and now ACEN), wherein MGI agreed to sell to PHINMA (now ACEN) the entire generated output of the MGPP-2 for a period of 20 years from start of commercial operations on April 30, 2018. On August 23, 2019, MGI and PHINMA (now ACEN) executed the Amendment to the Unit 1 ESA and Unit 2 ESA which, among others, extended the effectivity of both ESA-1 and ESA-2 until June 25, 2039. Solar Energy Service Contract for Tarlac On March 25, 2015, PetroGreen signed with the DOE a service contract for a 10-50 MWDC Solar Power Project near Hacienda Luisita, Tarlac: Solar Energy Service Contract No. 2015-03-115 (SESC). On June 17, 2015, the SEC approved the incorporation of PetroSolar. PetroGreen then assigned the SESC to PetroSolar, wherein PetroGreen and EEIPC hold 56% and 44% equity interests, respectively. The TSPP-1 was put on commercial operation on February 10, 2016. By the end of December 2018, PetroSolar started the construction of the 20 MWDC TSPP-2. The TSPP-2 was completed on March 2019 and underwent commissioning and testing on April 22, 2019. PetroSolar is now waiting for the ERC’s issuance of COC for TSPP-2. Omnibus Loan and Security Agreement (OLSA) with Philippine National Bank (PNB)

On May 19, 2010, PetroEnergy’s subsidiary, PetroGreen entered into a JVA with Trans-Asia (now ACEN) and PNOC RC whereby these companies agreed to pool their resources together to form a joint venture company to develop and operate the Maibarara geothermal field.

On November 12, 2015, PSC executed an OLSA with the PNB for a loan facility of up to = P2.6 billion to fund the 75% debt portion of the project cost of TSPP-1. PetroEnergy signed the OLSA as a Sponsor while PetroGreen signed as a Sponsor, Pledgor and Third-party Mortgagor. The TSPP-2 was funded through equity contributions and loans from its stockholders and through internally generated funds from the TSPP-1.

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Joint Venture Agreement (JVA)

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Renewable Energy Payment Agreement (REPA) Consequent to the issuance of FIT COC in its favor, PetroSolar entered into a REPA with the TransCo on April 6, 2016. Under the REPA, TransCo shall pay the FIT Rate of = P8.69/kWh for all metered generation of PSC for a period of twenty (20) years from start of Commercial Operations. FIT rate adjustment On May 26, 2020, the ERC approved Resolution No. 6 series of 2020 approving the adjustment to Feed in Tariff for the years 2016 to 2020 using 2014 as the base year for the consumer price index and foreign exchange. The resolution was published in a newspaper of general circulation on November 17, 2020 and became effective 15 days after. Total retroactive FIT revenue adjustment recognized in 2020 by PetroSolar amounted to = P132.69 million which will be recovered from TransCo for a period of five (5) years. As of December 31, 2020, contract asset amounted to = P132.69 million. Interest earned amounted to =0.26 million in 2020. P Solar Energy Service Contract (SESC) No. 2017-01-360 – Puerto Princesa, Palawan The Service Contract for the Puerto Princesa Solar Power Project (PPSPP) was signed by DOE Secretary Alfonso Cusi on February 27, 2017. The PPSPP aims to put up a 10-20 MW off-grid solar hybrid power facility in Puerto Princesa City, Palawan to meet the increasing electricity demand and address the fluctuating electricity situation in the city through solar power. Pre-development works have been commenced already, including technical and financial due diligence studies. Major permits such as the host local government unit’s favorable endorsements, the Strategic Environmental Plan (SEP) Clearance from the Palawan Council for Sustainable Development (PCSD), the Environmental Compliance Certificate (ECC) from the DENR-EMB Region IV-B, and the Certificate of Non-Overlap from the National Commission on Indigenous Peoples (NCIP), were already secured. PetroGreen has secured all local government endorsements needed for eventual facility development. In January 2020, PGEC was among seven (7) pre-qualified bidders for the 20-MW Palawan Main Grid Competitive Selection Process (CSP) of the Palawan Electric Cooperative (PALECO). On March 12, 2020, PALECO issued a bulletin which states that the submission and opening of bids was postponed until further notice. On January 18, 2021, PALECO issued a bulletin resuming the Palawan Main Grid 20-MW CSP after a 10-month postponement, with minor revisions to the bid terms as approved by the DOE and the National Electrification Administration (NEA). However, PGEC decided to withdraw from the said bidding process, owing to PALECO’s final Terms of Reference (TOR), which severely limit the economic feasibility of PGEC’s planned investment. PGEC is now exploring alternative offtake arrangements for PPSPP. Wind Energy Service Contract (WESC) No. 2017-09-118 – San Vicente, Palawan On November 11, 2019, the DOE officially awarded to PetroGreen the San Vicente, Palawan WESC. The WESC, effective October 9, 2019, vests PetroGreen with the rights and responsibilities to harness wind energy and develop and operate the corresponding renewable energy facility in the area. The

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proposed project is situated in the municipality of San Vicente, Palawan, approximately 130 km north of Puerto Princesa. Activities for the meteorological mast installation program for the San Vicente Wind Hybrid Power Project (SVWHPP) have been put on-hold due to COVID-19-related travel restrictions. Nonetheless, PGEC has secured on May 07, 2020 a Certificate of Non-Coverage (CNC) from the Department of Environment and Natural Resources (DENR) for the mast installation. In December 2020, PGEC’s contractor has mobilized to San Vicente, Palawan to carry out the installation works for the 60-meter meteorological mast to be used for the wind measurement campaign of the SVWHPP. The said mast is expected to be commissioned and turned-over to PGEC by April 2021. 34. Other Matters In a move to contain the COVID-19 outbreak, on March 13, 2020, the Office of the President of the Philippines issued a Memorandum directive to impose stringent social distancing measures in the National Capital Region effective March 15, 2020. On March 16, 2020, Presidential Proclamation No. 929 was issued, declaring a State of Calamity throughout the Philippines for a period of six (6) months and imposed an enhanced community quarantine throughout the island of Luzon until April 12, 2020. For selected areas, including Metro Manila, this was subsequently extended to May 31, 2020. The ECQ was lifted and replaced by general community quarantine (GCQ) starting June 1, 2020. On March 27, 2021, NCR and neighboring areas were placed under ECQ until April 11, 2021. These measures have caused disruptions to businesses and economic activities, and its impact on businesses continue to evolve. Manpower for operations may be affected due to the stateimposed self-quarantine, partial lockdown, and curfew. With the enforcing of national and localized community quarantines, the Group has issued guidelines to mitigate risks, ensure business continuity, and safeguard the health and safety of its employees. As an energy company with investments in petroleum and renewable energy, the Group is exposed to operational risks. Manpower for operations may be affected due to state-imposed self-quarantine, partial lockdown, and curfew. To address this, the management has devised an alternative working arrangement of workfrom-home and skeletal workforce scheme for its employees. Business support units were equipped with appropriate protocols and digital tools to be able to support the operations unit and ensure continuity of business operations. The management also ensured that the insurance coverage maintained for the Group would adequately compensate for any business interruptions. Due to travel restrictions, scheduled power plant maintenance by third-party foreign suppliers may also be affected. In preparation for this, the Group has communicated with its Operations and Maintenance (O&M) providers to strengthen its remote support and provide contingencies. The Group has also ensured that the insurance coverage maintained for the Group, its subsidiaries and affiliates, would adequately compensate for any business interruptions. For the oil operations in Gabon, the Group constantly communicated with the Operator and monitored the effect of the COVID-19 pandemic in the Gabon oil field. The Operator ensured that there is continued operations in the oil field, even with travel restrictions in the country.

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In addition, there is also the risk relating to compliance with regulatory permits and submissions due to changes in work schedule in both the public and private sectors. As a response, the Group regularly monitors the advisories from relevant Government agencies, such as the DOE, to ensure that requirements are submitted on time.

Applying the provisions of the CREATE Act, the Group would have been subjected to lower regular corporate income tax rate effective July 1, 2020. 

The provisions of Revenue Regulations (RR) No. 5-2021 was issued by the BIR dated April 8, 2021. This will result in lower provision for current income tax for the year ended December 31, 2020, amounting to P =34.45 million, or a reduction of = P1.22 million. This will also result in higher prepaid taxes and lower income tax payable as of December 31, 2020, amounting to = P15.31 million and = P6.94 million, respectively, or an increase (reduction) of P =0.19 million and (P =1.03 million), respectively. The reduced amounts will be reflected in the Group’s 2020 annual income tax return. However, for financial reporting purposes, the changes will only be recognized in the 2021 financial statements.



This will result in lower deferred tax assets - net as of December 31, 2020 by = P0.97 million and higher provision for deferred tax for the year then ended December 31, 2020 by = P0.97 million. These reductions will be recognized in the 2021 financial statements.

The Group considered the events surrounding the outbreak in its financial position and performance as of and for the year ended December 31, 2020. Even the impact for periods thereafter will be considered. Considering the evolving nature of this outbreak, the Group cannot determine at this time the impact to its financial position, performance and cash flows subsequent to 2020. The Group will continue to monitor the situation. 35. Subsequent Events President Rodrigo Duterte signed into law on March 26, 2021 the Corporate Recovery and Tax Incentives for Enterprises (CREATE) Act to attract more investments and maintain fiscal prudence and stability in the Philippines. Republic Act (RA) 11534 or the CREATE Act introduces reforms to the corporate income tax and incentives systems. It takes effect 15 days after its complete publication in the Official Gazette or in a newspaper of general circulation or April 11, 2021.

For the renewable energy operations of the Group, this is covered under the Renewable Energy Act of 2008, therefore, the CREATE Act has no impact on income tax for the renewable energy operations.

The following are the key changes to the Philippine tax law pursuant to the CREATE Act which have an impact on the Group: 

Effective July 1, 2020, regular corporate income tax (RCIT) rate is reduced from 30% to 25% for domestic and resident foreign corporations. For domestic corporations with net taxable income not exceeding Php5 million and with total assets not exceeding Php100 million (excluding land on which the business entity’s office, plant and equipment are situated) during the taxable year, the RCIT rate is reduced to 20%.

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Minimum corporate income tax (MCIT) rate reduced from 2% to 1% of gross income effective July 1, 2020 to June 30, 2023.

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Imposition of improperly accumulated earnings tax (IAET) is repealed.

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For investments prior to effectivity of CREATE: o

RBEs granted an ITH followed 5% GIT or are currently enjoying 5% GIT - allowed to avail of the 5% GIT for 10 years.

As clarified by the Philippine Financial Reporting Standards Council in its Philippine Interpretations Committee Q&A No. 2020-07, the CREATE Act was not considered substantively enacted as of December 31, 2020 even though some of the provisions have retroactive effect to July 1, 2020. The passage of the CREATE Act into law on March 26, 2021 is considered as a non-adjusting subsequent event. Accordingly, current and deferred taxes as of and for the year ended December 31, 2020 continued to be computed and measured using the applicable income tax rates as of December 31, 2020 (i.e., 30% RCIT / 2% MCIT) for financial reporting purposes.

*SGVFSM008891* 124 SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

*SGVFSM008891* PETROENERGY RESOURCES CORPORATION

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PROJECT SITE DIRECTORY HEAD OFFICE 7F JMT Corporate Building, ADB Avenue, Ortigas Center, Pasig City T: (632) 637-2917 / 637-5799 / 637-4032 / 637-4362 F: (632) 634-6066 / 633-8584

MAIBARARA GEOTHERMAL POWER FACILITY Plant Site: Sitio Capuz Brgy. San Rafael, Sto. Tomas, Batangas Logistics Station: 329 Maharlika Highway Brgy. Santiago, Sto Tomas, Batangas Tel no.: (043) 784-3328

NABAS WIND POWER FACILITY Plant Site: Brgy. Pawa, Nabas, Aklan Logistics Station: Brgy. Gibon Nabas, Aklan Tel no.: (036) 272-2714

TARLAC SOLAR POWER FACILITY Plant Site: Central Technopark, Brgy. Lourdes, Tarlac City Tel no.: (+632) 400-1448

126 SURVIVING DISRUPTIONS | 2020 ANNUAL REPORT

Sunset in the Wind Farm